CALGARY, ALBERTA — (Marketwire) — 02/16/12 — Nexen Inc. (TSX, NYSE: NXY) today reported 2011 fourth quarter and annual operating and financial results, and provided a progress update on its strategic priorities for 2012.
In the fourth quarter, we generated cash flow from operations of $585 million ($1.11/share), reflecting a 12% increase in production over the third quarter to 208,000 boe/d (193,000 boe/d after royalties), and cash netbacks from oil and gas operations of $42.85/boe (after-tax).
Net income was $43 million ($0.08/share), reflecting one-time, after-tax charges of $190 million ($0.36/share) related to previous costs associated with our shift away from large, integrated upgrading projects in our future oil sands development strategy, and $127 million after-tax ($0.24/share) for impairments related to our gas assets in Canada and the United States, due to low gas prices.
For the full year, cash flow was $2.4 billion ($4.49/share), net income was $697 million ($1.32/share) and production averaged 207,000 boe/d (186,000 boe/d after royalties). Cash netbacks from oil and gas operations were $40.20/boe (after-tax) in 2011.
The annual results met our expectations for cash flow ($2.1-$2.8 billion) and our revised expectations for production (200,000-215,000 boe/d). Total 2011 capital expenditures of $2.6 billion were also within our expected range of $2.4-$2.7 billion.
“Nexen delivered solid results in the fourth quarter,” said Kevin Reinhart, Nexen–s interim President & CEO. “Production met expectations, Long Lake generated positive cash flow, and we entered into two joint ventures in the Gulf of Mexico and shale gas with strong partners.
“I–m pleased with the commitment our employees have made to delivering on our strategic priorities for 2012 and beyond,” continued Reinhart. “2012 has started off strong. Long Lake production continues to grow and Buzzard is back to operating normally. We advanced our near term production growth projects including Usan, our UK tiebacks and Long Lake pads 12 and 13. We are also excited about our second drilling success on the Appomattox field in the Gulf of Mexico.”
Fourth Quarter Overview
2011 Overview
2012 Update
Results Summary
Fourth quarter cash flow from operations increased 13% over the third quarter primarily due to increased production and our rising cash netbacks. Annual cash flow from operations was the highest since 2008 as our weighting to unhedged, Brent-priced oil allowed us to realize premium pricing throughout the year. Brent averaged US$111 in 2011; this represented a $16 premium to WTI.
Net income declined quarter-over-quarter and year-over-year as a result of several items. It reflects a one-time charge of $190 million (after-tax) related to changes in our future oil sands development strategy. Our original strategy was to build duplicates of the existing Long Lake SAGD facilities and upgrader. We now expect to pursue smaller, phased, SAGD-only projects and will consider adding upgrading capacity once we are bitumen-long and economic conditions are favourable. As a result, previously capitalized design and engineering work done on the future phases has been expensed.
Lower annual net income also reflects impairments, primarily on our gas assets, in the third and fourth quarters of 2011, and gains on the sale of our heavy oil properties which increased net income in the third quarter of 2010.
Net debt has declined 13% in the past year and 36% over the past two years based on the success of our non-core asset disposition program.
Production Summary
Fourth quarter production increased 12% over the third quarter, primarily due to higher production from Buzzard and Long Lake.
Reliability at Buzzard significantly improved following completion of the commissioning of the fourth platform; our production efficiency rate was 86%. For 2012, we are targeting 85% before planned shutdowns (78% including scheduled downtime).
In the North Sea, the Blackbird tieback to Ettrick came on-stream in November, seven weeks ahead of schedule, and is currently producing to expectations; production in the fourth quarter was approximately 5,000 boe/d (gross). Severe weather resulted in longer than expected downtime to complete the Telford TAC tieback, which was finished in early February.
Long Lake bitumen production averaged 31,500 bbls/d (gross). This represents a 7% increase over the third quarter as production from the first 11 pads continues to increase and facility turnarounds were completed in the third quarter. At Syncrude, production was lower as a result of unscheduled maintenance on a hydrogen plant.
Production in Yemen and the Gulf of Mexico continued to experience natural declines; Yemen production was further reduced with the expiry of our contract for the Masila block in mid-December.
Production in 2011 was lower than 2010, primarily as a result of the sale of our heavy oil properties in the third quarter of 2010, natural declines, and production interruptions at Buzzard due to unplanned maintenance, third-party pipeline restrictions, and delays in commissioning the fourth platform.
We met our revised fourth quarter and annual production guidance.
Guidance Update
We are on track to achieve 2012 first quarter production guidance. Year-to-date production volumes are a little over 190,000 boe/d compared to our first quarter guidance range of 180,000-220,000 boe/d.
Buzzard has averaged approximately 185,000 boe/d (gross) so far this year, reflecting our operating efficiency of 85%. At Long Lake, bitumen production has increased to recent 7-day rates of approximately 35,000 bbls/d as pad 11 production continues to grow and we focus on production optimization from all wells.
At Long Lake, we have rescheduled the planned maintenance turnaround to take advantage of better labour availability. As a result, the three-week SAGD turnaround and six-week upgrader outage will now take place in the third quarter; they were previously scheduled for the second quarter. We have updated our second and third quarter guidance to reflect this change in timing.
Operational Update
Conventional
Offshore West Africa – Development of the Usan field remains on schedule; the project is our largest source of new production in 2012 and is expected to contribute to significantly stronger corporate cash netbacks this year. Final commissioning activities are in progress and first production is expected in the next month or two. Development activities were not affected by earlier civil unrest in Nigeria.
Usan–s facility capacity is 36,000 bbls/d net to Nexen; actual production rates will vary based on well performance, pace of ramp-up and facility uptime.
“First production from Usan will be a major achievement,” commented Reinhart. “The project is our newest legacy asset, and will generate significant cash flow for Nexen for many years. It also significantly strengthens our corporate netback, as the margin it generates is higher than our already strong corporate average.”
We expect to drill an exploration well at Owowo West in 2012. This well is targeted to follow-up on our earlier success at Owowo South B.
UK North Sea – Following final regulatory approval of the Golden Eagle development early in the fourth quarter, we began work on the fabrication of the facilities, utilizing many of the same teams that oversaw the successful construction of the Buzzard platforms. The work is proceeding on-time and on-budget, and we expect first production in late 2014. The facility will have a capacity of 70,000 boe/d (26,000 boe/d net to Nexen).
We also continue to progress our tieback projects in the North Sea. Blackbird came on-stream through the Ettrick facility in November and is currently producing to expectations. Telford TAC came on-stream in February; Rochelle is proceeding as planned and first production is expected around the end of 2012.
We have an active UK exploration program planned, including the North Uist exploration well west of the Shetland Islands, where drilling is expected to begin late in the first quarter.
Gulf of Mexico – At Appomattox, we followed-up our successful 2010 exploration well in the south fault block with another success in the northeast fault block. The well encountered approximately 150 feet of net oil pay; we are currently completing an evaluation to determine the size of the discovery. Resource on the northeast block would be in addition to the 65 million boe of probable reserves we booked on the south block.
We plan to continue drilling at Appomattox with an appraisal well on the south fault block and a sidetrack into the northwest fault block to test the third major part of the Appomattox structure. We have a 20% interest in Appomattox, the remaining interest is held by Shell Offshore Inc., who is the operator.
At Kakuna, we expect to reach target depth around the end of the first quarter. We expect to drill our next operated exploration well in the Gulf, at Angel Fire, later this year.
Oil Sands
Long Lake – At Long Lake, our focus is on advancing the 60 additional wells to fill the upgrader.
In the fourth quarter, Long Lake showed strong progress. Total production increased 7% over the prior quarter to 31,500 bbls/d of gross bitumen at a steam oil ratio (SOR) of 4.8.
Upgrader yield (PSC barrels per barrel of bitumen) was 76% and facility on-stream time was 78%. Per barrel operating costs were lower than previous quarters, primarily due to the increased production and the higher yield.
These factors contributed to positive cash flow from operations of $22 million in the quarter and $5 million for the full year.
1. Unit operating costs and realized prices are based on PSC and bitumen volumes sold and exclude activities related to third-party bitumen purchased, processed and sold. Unit operating cost includes energy cost.
Over the past few weeks, production at Long Lake has increased to approximately 35,000 bbls/d. This reflects successful and ongoing well optimization initiatives and the growth in pad 11 production. Pad 11 is currently producing approximately 4,500 bbls/d and is continuing to ramp-up. The expected production range for this pad is 4,000 to 8,000 bbls/d.
We are making steady progress on our plans to fill the upgrader. Drilling has concluded on pads 12 and 13, and well completion activities are underway. We remain on track to begin steaming pad 12 in the spring; pad 13 is expected to follow sometime in the late summer or early fall. Production from both pads is expected before the end of the year. These pads specifically targeted higher-quality resource; our drilling results confirm that the resource quality is as we expected.
The regulatory approvals for pads 14, 15 and K1A are progressing. We are awaiting approvals for one or both projects this spring, which would enable us to begin drilling next winter. These wells have geological characteristics similar to our current best-producing wells.
In aggregate, we anticipate these wells will allow us to fill the upgrader over the next several years:
“I am pleased with the progress we are making on our action plan to fill the upgrader,” said Reinhart. “We continue to increase production from our existing wells, and are on track to bring on-stream additional wells in the high-quality resource areas.”
We are also continuing work on a non-operated SAGD project at Hangingstone, of which we own 25%. The operator has delayed sanctioning of the project until late this year in order to complete the regulatory approval process. We expect the project to come on-stream in 2016 and our share of production at full rates will be about 6,000 bbls/d.
Shale Gas
Northeast British Columbia – We continued our strong execution on our Horn River shale gas program during the quarter. Our 9-well pad started up ahead of schedule and early production results are meeting expectations. Preliminary results indicate initial rates up to 18 mmcf/d per well. We are currently producing at our facility capacity of 50 mmcf/d.
Work continues on our 18-well pad and we remain on-time and on-budget. We anticipate production from this pad will begin in the fourth quarter, in conjunction with an increase in our facility capacity. This is expected to bring our total gross production capacity to 175 mmcf/d.
Our previously announced JV agreement with INPEX CORPORATION and JGC Corporation is expected to close in the second quarter 2012.
2011 Capital Investment and Reserves
In 2011, we invested $2.5 billion in oil and gas activities and added 73 million boe of proved reserves. These reserve additions replaced 96% of our production. On a proved plus probable basis, reserves increased 8%. Detailed tables outlining changes to reserves can be found on page 12 of this release.
The proved reserve additions relate primarily to the following areas:
We have 1 billion boe of proved reserves and 2.3 billion boe of proved plus probable reserves, representing reserve life indices of 13 years on a proved basis and 30 years on a proved plus probable basis. As previously disclosed, we also have a large inventory of attractive exploration prospects and billions of barrels of oil equivalent in contingent oil sands and shale gas resources. This provides a significant resource base for future growth.
Update on Executive Appointments
Nexen also announced today that Catherine Hughes, Executive Vice President of International, and Alan O–Brien, Senior Vice President, General Counsel & Secretary, have been confirmed in their current roles; both positions were previously held on an interim basis. Una Power, Nexen–s Senior Vice President of Corporate Planning & Business Development, has been appointed interim CFO; she also retains oversight for her previous responsibilities. Biographies of Nexen–s senior management team are available at .
Quarterly Dividend
The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable April 1st, 2012, to shareholders of record on March 9th, 2012.
About Nexen
Nexen Inc. is an independent, Canadian-based global energy company, listed on the Toronto and New York stock exchanges under the symbol NXY. Nexen is focused on three growth strategies: oil sands and shale gas in Western Canada and conventional exploration and development primarily in the North Sea, offshore West Africa and deepwater Gulf of Mexico. Nexen adds value for shareholders through successful full-cycle oil and gas exploration and development, and leadership in ethics, integrity, governance and environmental stewardship.
For further information on our shale gas joint venture, please refer to our press release dated November 29th, 2011. For more information on our estimates of reserves, please refer to our Annual Information Form. For more information on our estimates of resource, please refer to our press release dated November 15th, 2010.
Conference Call
Kevin Reinhart, Interim President & CEO, and Una Power, Interim CFO and Senior Vice President of Corporate Planning & Business Development, will discuss the financial and operating results as well as Nexen–s business strategy and future expectations.
The webcast will be archived under the Investors section of our website.
A replay of the call will be available for two weeks starting at 9:00 a.m. Mountain Time, February 16th by calling (905) 694-9451 (Toronto) or (800) 408-3053 (toll-free) passcode 2188506 followed by the pound sign.
Forward-Looking Statements
Certain statements in this release constitute “forward-looking statements” (within the meaning of the United States Private Securities Litigation Reform Act of 1995, as amended) or “forward-looking information” (within the meaning of applicable Canadian securities legislation). Such statements or information (together “forward-looking statements”) are generally identifiable by the forward-looking terminology used such as “anticipate”, “believe”, “intend”, “plan”, “expect”, “estimate”, “budget”, “outlook”, “forecast” or other similar words and include statements relating to or associated with individual wells, regions or projects.
Any statements as to possible future crude oil, natural gas or chemicals prices; future production levels; future royalties and tax levels; future capital expenditures, their timing and their allocation to exploration and development activities; future earnings; future asset acquisitions or dispositions; future sources of funding for our capital program; future debt levels; availability of committed credit facilities; possible commerciality of our projects; development plans or capacity expansions; the expectation that we have the ability to substantially grow production at our oil sands facilities through controlled expansions; the expectation of achieving the production design rates from our oil sands facilities; the expectation that our oil sands production facilities continue to develop better and more sustainable practices; the expectation of cheaper and more technologically advanced operations; the expected design size of our operations; the expected timing and associated production impact of facilities turnarounds and maintenance; the expectation that we can continue to operate our offshore exploration, development and production facilities safely and profitably; future ability to execute dispositions of assets or businesses; future sources of liquidity, cash flows and their uses; future drilling of new wells; ultimate recoverability of current and long-term assets; ultimate recoverability of reserves or resources; expected finding and development costs; expected operating costs, future cost recovery oil revenues from our Yemen operations; the expectation of our ability to comply with the new safety and environmental rules enacted in the US at a minimal incremental cost, and of receiving necessary drilling permits for our US offshore operations; estimates on a per share basis; future foreign currency exchange rates, future expenditures and future allowances relating to environmental matters and our ability to comply therewith; dates by which certain areas will be developed, come on stream or reach expected operating capacity; and changes in any of the foregoing are forward-looking statements. Statements relating to “reserves” or “resources” are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.
All of the forward-looking statements in this release are qualified by the assumptions that are stated or inherent in such forward-looking statements. Although we believe that these assumptions are reasonable, this list is not exhaustive of the factors that may affect any of the forward-looking statements and the reader should not place an undue reliance on these assumptions and such forward-looking statements. The key assumptions that have been made in connection with the forward-looking statements include the following: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve volumes; commodity price and cost assumptions; the continued availability of adequate cash flow and debt and/or equity financing to fund our capital and operating requirements as needed; and the extent of our liabilities. We believe the material factors, expectations and assumptions reflected in the forward-looking statements are reasonable, but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for oil and gas; our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; ultimate effectiveness of design or design modifications to facilities; the results of exploration and development drilling and related activities; the cumulative impact of oil sands development on the environment; the impact of technology on operations and processes and how new complex technology may not perform as expected; the availability of pipeline and global refining capacity; risks inherent to the operations of any large, complex refinery units, especially the integration between production operations and an upgrader facility; availability of third-party bitumen for use in our oil sands production facilities; labour and material shortages; risks related to accidents, blowouts and spills in connection with our offshore exploration, development and production activities, particularly our deepwater activities; direct and indirect risks related to the imposition of moratoriums, suspensions or cancellations of our offshore exploration, development and production operations, particularly our deepwater activities; the impact of severe weather on our offshore exploration, development and production activities, particularly our deepwater activities; the effectiveness and reliability of our technology in harsh and unpredictable environments; risks related to the actions and financial circumstances of our agents, counterparties, contractors, and joint venture parties; volatility in energy trading markets; foreign currency exchange rates; economic conditions in the countries and regions in which we carry on business; governmental actions including changes to taxes or royalties, changes in environmental and other laws and regulations including without limitation, those related to our offshore exploration, development and production activities; renegotiations of contracts; results of litigation, arbitration or regulatory proceedings; political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states; and other factors, many of which are beyond our control.
The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and management–s future course of action would depend on our assessment of all information at that time. Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Undue reliance should not be placed on the forward-looking statements contained herein, which are made as of the date hereof and, except as required by law, Nexen undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement. Readers should also refer to the Risk Factors contained in our 2010 Annual Information form, and to the Quantitative Disclosures about Market Risk and our Forward Looking Statements contained in our 2010 Management Discussion and Analysis.
Note to Investors on Reserves
The reserves estimates in this disclosure were prepared in February 2012 with an effective date of December 31, 2011. The estimates of reserves and future net revenue and have been internally prepared by an internal qualified reserves evaluator in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”). Nexen–s estimates of reserves prepared in accordance with SEC requirements are attached to its 2011 Annual Information Form.
Investors should note the following fundamental differences between reserves estimates and related disclosures prepared in accordance with NI 51-101 and those prepared in accordance with SEC requirements:
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 received an exemption from NI 51-101 that permits us to forego the requirement to have our NI 51-101 reserves and related future net revenue attributable to our reserves evaluated, audited or reviewed by an independent qualified reserves evaluator or auditor. Accordingly, our future net revenue and reserves estimates are based on internal evaluations. Due to the extent and expertise of our internal reserves evaluation resources, our staff–s familiarity with our properties and the controls applied to the evaluation process, we believe the reliability of our internally generated reserves estimates is not materially less than would be generated by an independent reserves evaluator.
Nexen Inc.
Financial Highlights
Cash Flow from Operations (1)
Nexen Inc.
Production Volumes (before royalties) (1)
Production Volumes (after royalties)
Nexen Inc.
Oil and Gas Prices and Cash Netback (1)
1. Netbacks are defined as average sales price less royalties and other,
operating costs and in-country taxes.
2. Includes Canadian conventional, CBM and shale gas activities. Shale gas
was included beginning in Q4, 2011 when it became commercial.
Nexen Inc.
Oil and Gas Cash Netback (1) (continued)
1. Netbacks are defined as average sales price less royalties and other,
operating costs and in-country taxes.
2. Excludes activities related to third-party bitumen purchased, processed
and sold.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Income
For the Three and Twelve Months Ended December 31
See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Unaudited Condensed Consolidated Balance Sheet
See accompanying notes to Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Cash Flows
For the Three and Twelve Months Ended December 31
See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Changes in Equity
For the Three and Twelve Months Ended December 31
See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Unaudited Condensed Consolidated Statement of Comprehensive Income
For the Three and Twelve Months Ended December 31
See accompanying notes to the Unaudited Condensed Consolidated Financial Statements.
Nexen Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Cdn$ millions, except as noted
1. BASIS OF PRESENTATION
Nexen Inc. (Nexen, we or our) is an independent, global energy company with operations in the North Sea, Gulf of Mexico, offshore West Africa, Canada, Yemen and Colombia. Nexen is incorporated and domiciled in Canada and our head office is located at 801-7th Avenue SW, Calgary, Alberta, Canada. Nexen–s shares are publicly traded on both the Toronto Stock Exchange and the New York Stock Exchange.
These Unaudited Condensed Consolidated Financial Statements for the three and twelve months ended December 31, 2011 have been prepared in accordance with International Accounting Standard (IAS) 34 Interim Financial Reporting. The Unaudited Condensed Consolidated Financial Statements do not include all of the information required for annual financial statements. Amounts relating to the three and twelve months ended December 31, 2010 were previously presented in accordance with Canadian GAAP. These amounts have been restated as necessary to be compliant with our accounting policies under International Financial Reporting Standards (IFRS) (see Note 2). Reconciliations and descriptions relating to the transition from Canadian GAAP to IFRS are included in Note 17.
The Unaudited Condensed Consolidated Financial Statements were authorized for issue on February 15, 2012 and should be read in conjunction with the Audited Consolidated Financial Statements for the year ended December 31, 2010, which have been prepared in accordance with Canadian GAAP.
2. ACCOUNTING POLICIES
The accounting policies we follow are described in Note 2 of the Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011.
Future Changes in Accounting Policies
As part of our transition to IFRS, we have adopted all IFRS accounting standards in effect on December 31, 2011.
The following standards and interpretations have not been adopted as they apply to future periods. They may result in future changes to our existing accounting policies and other note disclosures. We are evaluating the impacts that these standards may have on our results of operations, financial position and disclosure, except where indicated.
3. ACCOUNTS RECEIVABLE
Receivables terms are up to 30-days and were current as of December 31, 2011, December 31, 2010 and January 1, 2010.
4. INVENTORIES AND SUPPLIES
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 primarily include our Usan development, offshore Nigeria and developments in the UK North Sea.
(b) Impairment
DD&A expense for 2011 includes non-cash impairment charges of $322 million for our oil and gas properties in our Conventional North America segment. Canadian natural gas assets were impaired $234 million in the second half of 2011 due to lower estimated future natural gas prices and performance-related negative reserve revisions. In the fourth quarter, lower estimated future natural gas prices and higher estimated future abandonment costs resulted in an $88 million impairment of mature Gulf of Mexico properties.
DD&A expense for 2010 includes non-cash impairment charges of $139 million for properties in the US Gulf of Mexico and Canada. In the second half of 2010, low natural gas prices, higher estimated future abandonment costs and declining production performance impaired these properties.
The properties were written down to the higher amount of value-in-use and estimated fair value less costs to sell. We estimated fair value based on discounted future net cash flows using estimated future prices, a discount rate of 9% and management–s estimate of future production, capital and operating expenditures.
(c) Asset Derecognitions
Nexen–s original strategy for future oil sands development was to build duplicates of the existing Long Lake SAGD facilities and upgrader. We now expect to pursue smaller, phased, SAGD-only projects and we will consider adding upgrading capacity once we are bitumen-long and economic conditions are favourable. As a result, previously capitalized design and engineering costs of $253 million on the future phases have been expensed.
6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
7. LONG-TERM DEBT
(a) Term credit facilities
We have committed unsecured term credit facilities of $3.8 billion (US$3.7 billion) which were not drawn at either December 31, 2011 or December 31, 2010 (January 1, 2010-$1.6 billion (US$1.5 billion)). Of these facilities, $700 million is available until 2014 and $3.1 billion is available until 2016. Borrowings are available as Canadian bankers– acceptances, LIBOR-based loans, Canadian prime rate loans, US-dollar base rate loans or British pound call-rate loans. Interest is payable at floating rates. At December 31, 2011, $367 million of these facilities were utilized to support outstanding letters of credit (December 31, 2010-$322 million and January 1, 2010-$407 million).
(b) Redemption of Notes, due 2013
In the second quarter 2011, we redeemed and cancelled US$500 million of principal from bonds due in 2013. We paid $525 million for the redemption. We recorded a $52 million loss as the difference between carrying value and the redemption price.
(c) Repurchase for Cancellation of Certain 2015 and 2017 Notes
In the first quarter 2011, we repurchased and cancelled US$124 million and US$188 million of principal from the 2015 and 2017 bonds, respectively. We paid $346 million for the repurchase and recorded a $39 million loss as the difference between carrying value and the redemption price.
(d) Credit Facilities
Nexen has uncommitted, unsecured credit facilities of approximately $180 million (US$178 million), none of which were drawn at December 31, 2011, December 31, 2010 or January 1, 2010. We utilized $17 million of these facilities to support outstanding letters of credit at December 31, 2011 (December 31, 2010-$112 million and January 1, 2010-$86 million). Interest is payable at floating rates.
Nexen has uncommitted, unsecured credit facilities exclusive to letters of credit of approximately $213 million (US$210 million). We utilized $4 million of these facilities to support outstanding letters of credit at December 31, 2011 (December 31, 2010-nil and January 1, 2010-nil).
8. FINANCE EXPENSE
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 discounted the estimated asset retirement obligation using a weighted-average, credit-adjusted risk-free rate of 2.6% (2010-3.3%). While the provision for abandonment is based on our best estimates of future costs and the economic lives of the assets involved, there is uncertainty regarding both the amount and timing of incurring these costs. We expect approximately $428 million included in our ARO will be settled over the next five years with the balance settling beyond that. We expect to fund ARO from future cash flows from our operations.
10. RELATED PARTY DISCLOSURES
Major subsidiaries
The Unaudited Condensed Consolidated Financial Statements include the financial statements of Nexen Inc. and our subsidiaries as at December 31, 2011. The following is a list of the major subsidiaries of our operations. Transactions between subsidiaries are eliminated on consolidation. Nexen did not have any material related party transactions with entities outside the consolidated group in the years ended December 31, 2011 and 2010.
11. EQUITY
(a) Authorized Capital
Authorized share capital consists of an unlimited number of common shares of no par value and an unlimited number of Class A preferred shares of no par value, issuable in series. At December 31, 2011, there were 527,892,635 common shares outstanding (December 31, 2010-525,706,403 shares; January 1, 2010-522,915,843 shares). There were no preferred shares issued and outstanding as at December 31, 2011 (December 31, 2010-nil; January 1, 2010-nil). The rights, privileges, restrictions and conditions attached to common shares include a vote at all meetings of shareholders they are invited to, the receipt of any dividend declared by the board of directors on the common shares, and receipt of all remaining property of Nexen upon dissolution.
(b) Dividends
Dividends paid per common share for the three months ended December 31, 2011 were $0.05 per common share (three months ended December 31, 2010-$0.05). Dividends per common share for the year ended December 31, 2011 were $0.20 per common share (year ended December 31, 2010-$0.20). Dividends paid to holders of common shares have been designated as “eligible dividends” for Canadian tax purposes.
On February 15, 2012, the board of directors declared a quarterly dividend of $0.05 per common share, payable April 1, 2012 to the shareholders of record on March 9, 2012.
12. COMMITMENTS, CONTINGENCIES AND GUARANTEES
As described in Note 15 to the 2010 Audited Consolidated Financial Statements, there are a number of lawsuits and claims pending, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We believe that payments, if any, related to existing indemnities, would not have a material adverse effect on our liquidity, financial condition or results of operations.
We assume various contractual obligations and commitments in the normal course of our operations. During the quarter, we entered into commitments comprised of the following:
The commitments above are in addition to those included in Note 15 to the 2010 Audited Consolidated Financial Statements. Our operating leases, transportation and storage commitments, and other drilling rig commitments as at December 31, 2011 have not materially changed from the information previously disclosed in our 2010 Audited Consolidated Financial Statements.
13. MARKETING AND OTHER INCOME
14. DISPOSITIONS
(a) Discontinued Operations
In February 2011, we completed the sale of our 62.7% investment in Canexus, which operates a chemicals business, for net proceeds of $458 million and we realized a gain on disposition of $348 million in the first quarter. In the fourth quarter of 2010, we received board approval to sell our interest in Canexus and classified the assets and liabilities as held for sale at December 31, 2010. The gain on sale and results of our chemicals business have been presented as discontinued operations.
In July 2010, we completed the sale of our heavy oil properties in Canada. We received proceeds of $939 million, net of closing adjustments and realized a gain on disposition of $828 million in the third quarter of 2010. The gain on sale and results of operations of these properties have been presented as discontinued operations.
The following table provides the assets and liabilities that are associated with our chemicals business at December 31, 2010 and January 1, 2010. There were no assets or liabilities related to our chemical operations at December 31, 2011.
1. Included in assets and liabilities held for sale at December 31, 2010.
Amounts related to prior periods have not been reclassified.
(b) Asset Dispositions
UK North Sea
During the fourth quarter of 2011, we sold our non-operated working interest in the Duart field for proceeds of $38 million. The sale closed in December 2011 and we recognized a gain on sale of $38 million in the fourth quarter of 2011.
UK Undeveloped Lease
During the fourth quarter of 2010, we sold non-core lands in the UK North Sea for proceeds of $17 million. We had no plans to develop these leases. We recognized a gain on disposition of $17 million in the fourth quarter of 2010.
North Dakota/Montana Crude Oil Marketing
During the fourth quarter of 2010, we sold our oil lease gathering, pipelines and storage assets in North Dakota and Montana for proceeds of $201 million. The sale closed in December 2010 and we recognized a gain on disposition of $121 million in the fourth quarter of 2010.
15. CASH FLOWS
(a) Charges and credits to income not involving cash
(b) Changes in non-cash working capital
(c) Other cash flow information
16. OPERATING SEGMENTS AND RELATED INFORMATION
Effective in the first quarter of 2011, we amended our segment reporting to reflect changes in our business. In 2010, we disposed of non-core operations including heavy oil operations in Canada, chemicals and certain energy marketing businesses, and increased production at our Long Lake oil sands project. We report our segments to align with our key growth areas, specifically, Conventional Oil and Gas, Oil Sands and Shale Gas. Prior year results have been revised to reflect the presentation changes made in the current year.
Nexen has the following operating segments:
Conventional Oil and Gas: We explore for, develop and produce crude oil and natural gas from conventional sources around the world. Our operations are focused on the UK, North America (Canada and US) and other countries (offshore West Africa, Colombia and Yemen).
Oil Sands: We develop and produce synthetic crude oil from the Athabasca oil sands in northern Alberta. We produce bitumen using in situ and mining technologies and upgrade it into synthetic crude oil before ultimate sale. Our in situ activities are comprised of our operations at Long Lake and future development phases. Our mining activities are conducted through our 7.23% ownership of the Syncrude Joint Venture.
Shale Gas: We explore for and produce unconventional gas from shale formations in northeastern British Columbia. Production and results of operations are included within Conventional Oil and Gas until they become significant.
Corporate and Other includes energy marketing, unallocated items and the results of Canexus prior to its sale in February 2011. The results of Canexus have been presented as discontinued operations.
The accounting policies of our operating segments are the same as those described in Note 2 of our Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011. Net income (loss) of our operating segments excludes interest income, interest expense, unallocated corporate expenses and foreign exchange gains and losses. Identifiable assets are those used in the operations of the segments.
(1) Includes results of operations in Yemen and Colombia.
(2) Includes Masila net sales of $135 million and net income of $36 million.
(3) Includes non-cash impairment charges of $181 million in Canada and the US.
(4) Includes non-cash expenses of $253 million related to previously capitalized engineering and design costs.
(5) Includes exploration activities primarily in Nigeria, Norway, Colombia and Poland.
(6) Includes capital expenditures in Nigeria of $193 million.
(1)Includes results of operations in Yemen and Colombia.
(2)Includes Masila net sales of $143 million and net income of $43 million.
(3)Includes exploration activities primarily in Yemen, Nigeria, Norway and Colombia.
(4)Gain on disposition of UK undeveloped lease.
(5)Gain on disposition of North Dakota/Montana Crude Oil Marketing assets.
(6)Includes capital expenditures in Nigeria of $158 million.
(1) Includes results of operations in Yemen and Colombia.
(2) Includes Masila net sales of $588 million and net income of $161 million.
(3) Includes non-cash impairment charges of $322 million in Canada and the US.
(4) Includes non-cash expenses of $253 million related to previously capitalized engineering and design costs.
(5) Includes exploration activities primarily in Nigeria, Norway, Colombia and Poland.
(6) Includes capital expenditures in Nigeria of $542 million.
(1)Includes results of operations in Yemen and Colombia.
(2)Includes Masila net sales of $570 million and net income of $156 million.
(3)Includes non-cash impairment charges of $139 million for Canada and the US.
(4)Includes exploration activities primarily in Yemen, Nigeria, Norway and Colombia.
(5)Gain on disposition of UK undeveloped lease.
(6)Gain on disposition of non-core lands in the Athabasca region.
(7)Net loss on disposition of Natural Gas Energy Marketing Business and North Dakota/Montana Crude Oil Marketing assets.
(8)Includes capital expenditures in Nigeria of $495 million.
(1)Includes cash of $453 million, and Energy Marketing accounts receivable and inventory of $1,449 million.
(2)Includes capitalized costs of $1,293 million associated with our Canadian shale gas operations.
(3)Includes $1,821 million related to our Usan development, offshore Nigeria.
(4)Includes net book value of $5,050 million for Long Lake Phase 1 and $660 million for future phases of our in situ oil sands projects.
(1)Includes cash of $817 million, Energy Marketing accounts receivable and inventory of $1,498 million and Chemicals assets of $729 million.
(2)Includes capitalized costs of $938 million associated with our Canadian shale gas operations.
(3)Includes $1,210 million related to our Usan development, offshore Nigeria.
(4)Includes net book value of $4,865 million for Long Lake Phase 1 and $800 million for future phases of our in situ oil sands projects.
(1)Includes cash of $1,016 million, Energy Marketing accounts receivable and inventory of $2,392 million and Chemicals assets of $654 million.
(2)Includes capitalized costs of $477 million associated with our Canadian shale gas operations.
(3)Includes $760 million related to our Usan development, offshore Nigeria.
(4)Includes net book value of $4,776 million for Long Lake Phase 1 and $740 million for future phases of our in situ oil sands projects.
17. TRANSITION TO IFRS
For all periods up to and including the year ended December 31, 2010, we prepared our Consolidated Financial Statements in accordance with Canadian generally accepted accounting principles (Canadian GAAP). As a publicly listed company in Canada, we are required to prepare consolidated financial statements in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) for all periods after January 1, 2011 including comparative historical information. As we are also publicly listed in the United States, we were required to include a reconciliation of our financial results between Canadian GAAP and US GAAP. The reconciliation to US GAAP is no longer required.
In accordance with transitional provisions, we prepared our opening balance sheet as at January 1, 2010 (the transition date) and 2010 comparative financial information using the accounting policies set out in Note 2 of the Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011. The consolidated financial statements for the year ended December 31, 2011 will be the first annual financial statements that comply with IFRS by applying existing IFRS with an effective date of December 31, 2011 or earlier. This transition note explains the material adjustments we made to convert our financial statements to IFRS.
Elected Exemptions from Full Retrospective Application
In preparing these Unaudited Condensed Consolidated Financial Statements in accordance with IFRS 1 First-time Adoption of International Financial Reporting Standards (IFRS 1), we applied the following optional exemptions from full retrospective application of IFRS.
(i) Business Combinations
We applied the business combinations exemption to not apply IFRS 3 Business Combinations retrospectively to past business combinations. Accordingly, we have not restated business combinations that took place prior to the transition date.
(ii) Fair Value or Revaluation as Deemed Cost
We elected to measure certain producing oil and gas properties at fair value as at the transition date and use that amount as its deemed cost in the opening IFRS balance sheet.
(iii) Cumulative Translation Differences
We elected to set the cumulative translation account to nil at January 1, 2010. This exemption has been applied to all subsidiaries.
(iv) Share-Based Payment Transactions
We elected to use the IFRS 1 exemption whereby the liabilities for share-based payments that had vested or settled prior to January 1, 2010 were not required to be retrospectively restated.
(v) Employee Benefits
We elected to apply the exemption for employee benefits to recognize the accumulated unrecognized net actuarial loss in retained earnings at January 1, 2010. This exemption has been applied to all defined benefit pension plans.
(vi) Asset Retirement Obligations
We applied the exemption from full retrospective application of our asset retirement obligations as permitted for first-time adoption of IFRS. As such, we re-measured ARO as at January 1, 2010. We estimated the amount to be included in the related asset by discounting the liability to the date when the obligation first arose using our best estimates of the historical risk-free discount rates applicable during the intervening period.
(vii) Borrowing Costs
We applied an IFRS transitional exemption to prospectively capitalize borrowing costs only from the transition date. As a result, borrowing costs previously capitalized under Canadian GAAP were expensed to retained earnings.
Mandatory Exceptions to Retrospective Application
In preparing these Unaudited Condensed Consolidated Financial Statements in accordance with IFRS 1, we were required to apply the following mandatory exceptions from full retrospective application of IFRS.
(i) Hedge Accounting
Only hedging relationships that satisfied the hedge accounting criteria as of the transition date are reflected as hedges in our results under IFRS. Any derivatives not meeting the IAS 39 Financial Instruments: Recognition and Measurement criteria for hedge accounting were recorded as a non-hedging derivative financial instrument.
(ii) Estimates
Hindsight was not used to create or revise estimates and accordingly, our estimates previously made under Canadian GAAP are consistent with their application under IFRS.
Reconciliations of Canadian GAAP to IFRS
IFRS 1 requires the presentation of a reconciliation of shareholders– equity, net income, comprehensive income, and cash flows for prior periods. The transition from Canadian GAAP to IFRS had no material effect upon previously reported cash flows. The following represents the reconciliations from Canadian GAAP to IFRS for the respective periods for shareholders– equity, net income, and comprehensive income:
Reconciliation of Shareholders– Equity
(i) Borrowing Costs
We applied the IFRS 1 exemption to prospectively capitalize borrowing costs only from the transition date as described above.
(ii) Asset Retirement Obligations (ARO)
We applied the IFRS 1 exemption for asset retirement obligations and re-measured our ARO as at January 1, 2010 as described above.
(iii) Employee Benefits
We have chosen to include previously unrecognized actuarial gains and losses of our defined benefit pension plans on the balance sheet under IFRS. Under Canadian GAAP, we amortized actuarial gains and losses to income over the estimated average remaining service life, with disclosure of the unrecognized amount in the notes to the Consolidated Financial Statements. On January 1, 2010, we applied the IFRS 1 exemption to recognize the accumulated unrecognized net actuarial loss in retained earnings on transition to IFRS.
(iv) Stock-Based Compensation (SBC)
Under Canadian GAAP, we recorded obligations for liability-based stock compensation plans using the intrinsic-value method of accounting. IFRS requires that we record these SBC obligations at fair value and subsequently re-measure the obligation each reporting period. Our tandem option, stock appreciation rights and restricted share unit plans are considered liability-based stock compensation plans. On transition, we recorded the liability at fair value for unsettled awards.
(v) Property, Plant and Equipment
Impairment
Under Canadian GAAP, if indications of impairment exist and the asset–s estimated undiscounted future cash flows were lower than its carrying amount, the carrying value was written down to fair value. Under IFRS, if indications of impairments exist, the asset–s carrying value is immediately compared to its estimated recoverable amount, which could trigger additional impairment under IFRS. We elected to measure certain producing oil and gas properties at fair value as at the transition date and use that amount as its deemed cost in the opening IFRS balance sheet. As a result, oil and gas properties were written down to fair value of $460 million and resulted in an impairment expense of $91 million on transition.
Componentization
Under Canadian GAAP, we depleted oil and gas capitalized costs using the unit-of-production method on a field-by-field basis and depreciated non-resource capitalized costs based on their estimated useful life. On adoption of IFRS, we reviewed our PP&E to identify each material component that has a significantly different useful life and as a result, adjustments to the accumulated depletion of certain assets resulted in an expense of $51 million on transition to IFRS.
Major Maintenance
Under Canadian GAAP, operating expenses included major maintenance costs that were expensed as incurred. Under IFRS, $18 million was capitalized and depreciated separately until the next planned major maintenance project.
(vi) Foreign Exchange
Foreign Currency Translation
We applied the first-time IFRS adoption exemption to reset our cumulative translation differences to nil on the transition date. Accumulated foreign exchange gains and losses of our self-sustaining foreign operations, net of foreign exchange translation gains and losses of long-term debt designated as hedges are included in retained earnings on the transition date. This one-time adjustment had no impact on shareholders– equity on transition.
Change in Functional Currency
As a result of additional guidance under IFRS, our assessment of the functional currency of a subsidiary changed from Canadian dollars to US dollars to better reflect the economic environment in which it operates.
(vii) Long-Term Debt
Canexus Convertible Debentures
Canexus unitholders have the ability to redeem fund units for cash pursuant to the terms of the trust indenture. Under IFRS, these convertible debentures are considered to be financial liabilities containing an embedded derivative. Under Canadian GAAP, the convertible debentures were considered to be compound instruments with an equity component. Accordingly, the equity component and unamortized deferred transaction costs recorded under Canadian GAAP were derecognized on January 1, 2010 and charged to retained earnings. We elected to recognize the convertible debentures at fair value and to recognize changes in fair value in net income during the period of change.
(viii) Income Taxes
Recognition of Deferred Tax Credit
In 2008, we completed an internal reorganization and financing of our assets in the North Sea, which provided us with a one-time tax deduction in the UK. Canadian GAAP precluded us from recognizing the full estimated benefit of the tax deductions until the assets were recognized in net income either by a sale or depletion through use. As a result, we deferred the initial recognition of the benefit and were amortizing it to future income tax expense over the life of the underlying assets under Canadian GAAP. On adoption of IFRS, no such prohibition exists and we recognized the remaining deferred tax credit in retained earnings on transition to IFRS.
Exceptions
Under Canadian GAAP, deferred taxes were generally provided on all temporary differences. Conversely, IFRS does not recognize deferred taxes on temporary differences arising from the initial recognition of assets or liabilities in transactions that are not business combinations and that affect neither accounting nor taxable profit or loss.
Reconciliation of Net Income
(i) Borrowing Costs
We applied an IFRS transitional exemption to prospectively capitalize borrowing costs from the transition date. As a result, borrowing costs previously capitalized under Canadian GAAP were expensed to shareholders– equity. The reduced capitalized amounts decreased DD&A expense during 2010.
(ii) Asset Retirement Obligations (ARO)
Under Canadian GAAP, foreign exchange translation gains and losses arising from the revaluation of GBP-denominated asset retirement obligations were included in net income in the period in which they occurred. Under IFRS, these translation gains and losses are treated as a change in estimate and therefore increase or decrease PP&E with a corresponding impact on net income.
(iii) Stock-Based Compensation (SBC)
As described above, we record obligations for liability-based stock compensation plans at fair value each reporting period. Our tandem option, stock appreciation rights and restricted share unit plans are considered liability-based stock compensation plans. The changes in the SBC fair value in 2010 were recognized in net income.
(iv) Property, Plant and Equipment
Impairment
As described above, certain properties were impaired and written down to fair value on transition. These adjustments reduced IFRS DD&A expense during 2010 by immaterial amounts. In the last half of 2010, additional properties were impaired and written down to fair value. The impairment expense of $46 million reduced net income in the third and fourth quarters.
Major Maintenance Costs
As described above, Canadian GAAP operating expenses included major maintenance costs that were expensed as incurred. Under IFRS, these costs are capitalized and depreciated separately until the next planned major maintenance project. During 2010, we capitalized $18 million of maintenance costs under IFRS that were expensed as operating costs under Canadian GAAP.
Gain on Sale of Heavy Oil Properties
We completed the sale of our Canadian heavy oil properties in the third quarter of 2010. As the adoption of IFRS resulted in different carrying values of property, plant & equipment and asset retirement obligations prior to the sale, our gain on sale under IFRS was $47 million higher.
(v) Long-Term Debt
Canexus Convertible Debentures
As described above, we elected to carry the Canexus convertible debentures at fair value under IFRS. The change in fair value during 2010 was included in net income.
(vi) Income Taxes
Recognition of Deferred Tax Credit
As described above, we amortized a deferred tax credit to income over the life of the underlying asset under Canadian GAAP. Under IFRS, the deferred tax credit was recognized in retained earnings on transition. Therefore, IFRS net income was lower by $29 million and $117 million for the three and twelve months ended December 31, 2010, respectively.
Other
All other adjustments to IFRS net income were tax effected which decreased deferred tax expense $31 and increased $19 million for the three and twelve months ended December 31, 2010, respectively.
Reconciliation of Comprehensive Income
(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