CALGARY, ALBERTA — (Marketwire) — 08/04/11 — Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ)
Commenting on second quarter results, Canadian Natural–s Chairman, Allan Markin stated, “Our skilled and experienced technical, operational and financial teams, along with our balanced assets continue to deliver. We generated solid cash flow results even while production at Horizon remained suspended in the second quarter. We maintain a safe, responsible, efficient operating environment which allows us to effectively execute on our plans. With the Horizon rebuild and repairs now essentially complete and commissioning underway, we look forward to additional cash flow generation for the remainder of 2011.”
John Langille, Vice-Chairman of Canadian Natural continued, “We maintain sufficient available liquidity which will sustain our operations in the short, medium and long term. We continue to take advantage of our diverse asset base through effective capital allocation to higher return projects. Our favorable debt to book capital ratio of 29% supports our future growth strategy and our ability to be flexible in our decision making and capital allocation.”
Steve Laut, President of Canadian Natural stated, “Canadian Natural is positioned to generate significant shareholder value going forward with production at Horizon set to resume in the third quarter along with the solid overall performance in the rest of the asset base so far in 2011. At Horizon, we are committed to a disciplined execution strategy to achieve cost certainty for expansions from the current 110,000 bbl/d of SCO capacity to 250,000 bbl/d of SCO capacity. Our high quality, balanced asset base has allowed us to allocate capital to the highest return projects and the business is set to deliver significant free cash flow going forward.”
QUARTERLY HIGHLIGHTS
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural focuses its activities in core regions where it can dominate the land base and infrastructure. Land inventories are maintained to enable continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By dominating infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production costs. Further, the Company maintains large project inventories and production diversification among each of the commodities it produces; namely natural gas, light/medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), SCO and NGLs. A large diversified project portfolio enables the effective allocation of capital to higher return opportunities.
OUTLOOK
The Company forecasts 2011 production levels before royalties to average between 1,250 and 1,275 MMcf/d of natural gas and between 371,000 and 406,000 bbl/d of crude oil and NGLs. Q3/11 production guidance before royalties is forecast to average between 1,230 and 1,255 MMcf/d of natural gas and between 373,000 and 414,000 bbl/d of crude oil and NGLs. Detailed guidance on production levels, capital allocation and operating costs can be found on the Company–s website at .
MANAGEMENT–S DISCUSSION AND ANALYSIS
Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (the “Company”) in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words “believe”, “anticipate”, “expect”, “plan”, “estimate”, “target”, “continue”, “could”, “intend”, “may”, “potential”, “predict”, “should”, “will”, “objective”, “project”, “forecast”, “goal”, “guidance”, “outlook”, “effort”, “seeks”, “schedule” or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes and costs, royalties, operating costs, capital expenditures, income tax expenses and other guidance provided throughout this Management–s Discussion and Analysis (“MD&A”), constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including but not limited to the Horizon Oil Sands resumption of production and future expansion, ability to recover insurance proceeds, Primrose, Pelican Lake, Olowi Field (Offshore Gabon), the Kirby Thermal Oil Sands Project, the Keystone Pipeline US Gulf Coast expansion, and the construction and operation of the North West Redwater bitumen refinery also constitute forward-looking statements. This forward-looking information is based on annual budgets and multi-year forecasts, and is reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur.
In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates.
The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of the Company–s products; volatility of and assumptions regarding crude oil and natural gas prices; fluctuations in currency and interest rates; assumptions on which the Company–s current guidance is based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; the Company–s defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company–s and its subsidiaries– ability to secure adequate transportation for its products; unexpected difficulties in mining, extracting or upgrading the Company–s bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting or upgrading the Company–s bitumen products; availability and cost of financing; the Company–s and its subsidiaries– success of exploration and development activities and their ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies; production levels; imprecision of reserve estimates and estimates of recoverable quantities of crude oil, natural gas and natural gas liquids (“NGLs”) not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital and operating costs); asset retirement obligations; the adequacy of the Company–s provision for taxes; and other circumstances affecting revenues and expenses.
The Company–s operations have been, and in the future may be, affected by political developments and by federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company–s assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company–s course of action would depend upon its assessment of the future considering all information then available.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by law, the Company assumes no obligation to update forward-looking statements should circumstances or Management–s estimates or opinions change.
Management–s Discussion and Analysis
Management–s Discussion and Analysis of the financial condition and results of operations of the Company should be read in conjunction with the unaudited interim consolidated financial statements for the six months ended June 30, 2011 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2010.
All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. Common share data and per common share amounts have been restated to reflect the two-for-one share split in May 2010. The Company–s consolidated financial statements for the period ended June 30, 2011 and this MD&A have been prepared in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”). Unless otherwise stated, 2010 comparative figures have been restated in accordance with IFRS issued as at August 3, 2011. Any subsequent changes to IFRS that are given effect in the Company–s annual consolidated financial statements for the year ending December 31, 2011 could result in restatement of the prior periods. This MD&A includes references to financial measures commonly used in the crude oil and natural gas industry, such as adjusted net earnings from operations, cash flow from operations, and cash production costs. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate its performance. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings, as determined in accordance with IFRS, as an indication of the Company–s performance. The non-GAAP measures adjusted net earnings from operations and cash flow from operations are reconciled to net earnings, as determined in accordance with IFRS, in the “Financial Highlights” section of this MD&A. The derivation of cash production costs is included in the “Operating Highlights – Oil Sands Mining and Upgrading” section of this MD&A. The Company also presents certain non-GAAP financial ratios and their derivation in the “Liquidity and Capital Resources” section of this MD&A.
The calculation of barrels of oil equivalent (“BOE”) is based on a conversion ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil to estimate relative energy content. This conversion may be misleading, particularly when used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent the value equivalency at the wellhead.
Production volumes and per barrel statistics are presented throughout this MD&A on a “before royalty” or “gross” basis, and realized prices are net of transportation and blending costs and exclude the effect of risk management activities. Production on an “after royalty” or “net” basis is also presented for information purposes only.
The following discussion refers primarily to the Company–s financial results for the six and three months ended June 30, 2011 in relation to the comparable periods in 2010 and the first quarter of 2011. The accompanying tables form an integral part of this MD&A. This MD&A is dated August 3, 2011. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2010, is available on SEDAR at , and on EDGAR at .
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
Net earnings for the six months ended June 30, 2011 were $975 million compared to $1,386 million for the six months ended June 30, 2010. Net earnings for the six months ended June 30, 2011 included net unrealized after-tax income of $126 million related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates and the impact of statutory tax rate and other legislative changes on deferred income tax liabilities, compared to net unrealized after-tax income of $100 million for the six months ended June 30, 2010. Excluding these items, adjusted net earnings from operations for the six months ended June 30, 2011 were $849 million, compared to $1,286 million for the six months ended June 30, 2010.
Net earnings for the second quarter of 2011 were $929 million compared to $651 million for the second quarter of 2010 and $46 million for the prior quarter. Net earnings for the second quarter of 2011 included net unrealized after-tax income of $308 million related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates and the impact of statutory tax rate and other legislative changes on deferred income tax liabilities, compared to net unrealized after-tax income of $4 million for the second quarter of 2010 and net unrealized after-tax expenses of $182 million for the prior quarter. Excluding these items, adjusted net earnings from operations for the second quarter of 2011 were $621 million compared to $647 million for the second quarter of 2010 and $228 million for the prior quarter.
The decrease in adjusted net earnings for the six and three months ended June 30, 2011 from the comparable periods in 2010 was primarily due to lower synthetic crude oil (“SCO”) sales revenue and continuing production expenses associated with the suspension of production at Horizon. On January 6, 2011, a fire occurred at the Company–s primary upgrading coking plant. As at August 3, 2011, all necessary regulatory and operating approvals to recommence operations were received. Final mechanical, testing and commissioning activities are ongoing and production is scheduled to commence in the third quarter of 2011.
Other factors contributing to the decrease in adjusted net earnings were:
The impacts of share-based compensation, unrealized risk management activities and changes in foreign exchange rates are expected to continue to contribute to quarterly volatility in consolidated net earnings and are discussed in detail in the relevant sections of this MD&A.
Cash flow from operations for the six months ended June 30, 2011 was $2,622 million compared to $3,136 million for the six months ended June 30, 2010. Cash flow from operations for the second quarter of 2011 was $1,548 million compared to $1,629 million for the second quarter of 2010 and $1,074 million for the prior quarter. The decrease in cash flow from operations from the comparable periods in 2010 was primarily due to lower SCO sales revenue and continuing production expenses associated with the suspension of production at Horizon. Other factors contributing to the decrease were:
The increase in cash flow from operations from the prior quarter was primarily due to:
Total production before royalties for the six months ended June 30, 2011 decreased 11% to 561,359 BOE/d from 629,982 BOE/d for the six months ended June 30, 2010. Total production before royalties for the second quarter of 2011 decreased 14% to 556,539 BOE/d from 649,195 BOE/d for the second quarter of 2010 and 2% from 566,231 BOE/d for the prior quarter. Production for the second quarter of 2011 was within the Company–s previously issued guidance.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company–s quarterly results for the eight most recently completed quarters:
Volatility in the quarterly net earnings (loss) over the eight most recently completed quarters was primarily due to:
Commodity Prices
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$98.42 per bbl for the six months ended June 30, 2011, an increase of 26% from US$78.39 per bbl for the six months ended June 30, 2010. WTI averaged US$102.55 per bbl for the second quarter of 2011, an increase of 31% from US$77.99 per bbl for the second quarter of 2010, and an increase of 9% from US$94.25 per bbl for the prior quarter. WTI pricing was reflective of the political instability in the Middle East and North Africa, continued strong Asian demand and the relative weakness of the US dollar.
Crude oil sales contracts for the Company–s North Sea and Offshore Africa segments are typically based on Dated Brent (“Brent”) pricing, which is more representative of international markets and overall world supply and demand. Brent averaged US$111.20 per bbl for the six months ended June 30, 2011, an increase of 44% compared to US$77.30 per bbl for the six months ended June 30, 2010. Brent averaged US$117.33 per bbl for the second quarter of 2011, an increase of 50% compared to US$78.27 per bbl for the second quarter of 2010 and an increase of 12% from US$105.01 per bbl for the prior quarter. The higher Brent pricing relative to WTI was due to logistical constraints and high inventory levels of crude oil at Cushing.
The Western Canadian Select (“WCS”) Heavy Differential averaged 20% for the six months ended June 30, 2011 compared to 15% for the six months ended June 30, 2010. The WCS Heavy Differential widened from the comparable period in 2010 partially due to the continuing effects of pipeline disruptions in the last half of 2010 that forced the temporary shutdown and apportionment of major oil pipelines to Midwest refineries in the United States. The WCS Heavy Differential averaged 17% for the second quarter of 2011, compared to 18% for the second quarter of 2010 and 24% for the prior quarter. The WCS Heavy Differential narrowed in the second quarter of 2011, compared to the prior quarter, partially due to a stronger diesel market, and the impact of unplanned outages at upgrading facilities and planned refinery shutdowns in key markets for WCS that occurred in the prior quarter.
The Company uses condensate as a blending diluent for heavy crude oil pipeline shipments. During the second quarter of 2011, condensate prices continued to trade at a premium to WTI, similar to the second quarter of 2010 and the prior quarter, reflecting normal seasonality.
The Company anticipates continued volatility in crude oil pricing benchmarks due to supply and demand factors, geopolitical events, and the timing and extent of the continuing economic recovery. The WCS Heavy Differential is expected to continue to reflect seasonal demand fluctuations, logistics and refinery margins.
NYMEX natural gas prices averaged US$4.24 per MMbtu for the six months ended June 30, 2011, a decrease of 10% from US$4.72 per MMbtu for the six months ended June 30, 2010. NYMEX natural gas prices averaged US$4.36 per MMbtu for the second quarter of 2011, an increase of 7% from US$4.08 per MMbtu for the second quarter of 2010, and an increase of 6% from US$4.13 per MMbtu for the prior quarter.
AECO natural gas prices for the six months ended June 30, 2011 averaged $3.56 per GJ, a decrease of 18% from $4.36 per GJ for the six months ended June 30, 2010. AECO natural gas prices for the second quarter of 2011 decreased 3% to average $3.54 per GJ from $3.66 per GJ in the second quarter of 2010, and were comparable to the prior quarter.
Weather in the United States in 2011 resulted in stronger natural gas prices and reduced inventory levels which partially offset strong incremental production from shale gas reservoirs. Overall gas prices continue to be weak in response to the strong North America supply position, primarily from the highly productive shale areas.
The Company–s business approach is to maintain large project inventories and production diversification among each of the commodities it produces; namely natural gas, light and medium crude oil and NGLs, Pelican Lake heavy crude oil, primary heavy crude oil, bitumen (thermal oil), and SCO.
Crude oil and NGLs production for the six months ended June 30, 2011 decreased 17% to 353,433 bbl/d from 424,757 bbl/d for the six months ended June 30, 2010. Crude oil and NGLs production for the second quarter of 2011 decreased 21% to 349,915 bbl/d from 443,045 bbl/d for the second quarter of 2010, and 2% from 356,988 bbl/d for the prior quarter. The decrease from the comparable periods in 2010 and the prior quarter was primarily related to the suspension of production at Horizon, partially offset by the impact of a record heavy oil drilling program and the cyclic nature of the Company–s thermal operations. Crude oil and NGLs production in the second quarter of 2011 was within the Company–s previously issued guidance of 345,000 to 376,000 bbl/d.
Natural gas production for the six months ended June 30, 2011 averaged 1,248 MMcf/d compared to 1,231 MMcf/d for the six months ended June 30, 2010. Natural gas production for the second quarter of 2011 averaged 1,240 MMcf/d and was comparable to the second quarter of 2010 and decreased 1% compared to 1,256 MMcf/d for the prior quarter. The increase in natural gas production from the six months ended June 30, 2010 reflects the new production volumes from the Septimus facility in North East British Columbia and from natural gas producing properties acquired during 2010 and 2011. These increases were partially offset by expected production declines due to the allocation of capital to higher return crude oil projects, which resulted in a strategic reduction of natural gas drilling activity. Natural gas production in the second quarter of 2011 was within the Company–s previously issued guidance of 1,219 to 1,244 MMcf/d.
For 2011, revised annual production guidance is targeted to average between 371,000 and 406,000 bbl/d of crude oil and NGLs and between 1,250 and 1,275 MMcf/d of natural gas. Third quarter 2011 production guidance is targeted to average between 373,000 and 414,000 bbl/d of crude oil and NGLs and between 1,230 and 1,255 MMcf/d of natural gas.
North America – Exploration and Production
North America crude oil and NGLs production for the six months ended June 30, 2011 increased 11% to average 292,938 bbl/d from 264,081 bbl/d for the six months ended June 30, 2010. For the second quarter of 2011, crude oil and NGLs production increased 7% to average 295,715 bbl/d, compared to 275,584 bbl/d for the second quarter of 2010, and increased 2% compared to 290,130 bbl/d for the prior quarter. Increases in crude oil and NGLs production from comparable periods were primarily due to the impact of a record heavy oil drilling program and the cyclic nature of the Company–s thermal operations. North America production volumes were negatively impacted by forest fires in North Central Alberta and flooding in South East Saskatchewan in the second quarter of 2011, which caused temporary production curtailments of certain fields including Pelican Lake. Accordingly, production of crude oil and NGLs was at the low end of the Company–s previously issued guidance of 295,000 bbl/d to 310,000 bbl/d for the second quarter of 2011.
Natural gas production for the six months ended June 30, 2011 increased 1% to 1,221 MMcf/d compared to 1,206 MMcf/d for the six months ended June 30, 2010. Natural gas production of 1,218 MMcf/d in the second quarter of 2011 was comparable to the second quarter of 2010 and the prior quarter. The slight increase in natural gas production for the six months ended June 30, 2011 from the comparable period in 2010 reflected new production volumes from the Septimus facility in North East British Columbia and from natural gas producing properties acquired during 2010 and 2011. These increases were partially offset by expected production declines due to the allocation of capital to higher return crude oil projects, which resulted in a strategic reduction of natural gas drilling activity with 10 natural gas wells drilled in the second quarter of 2011. Production of natural gas was within the Company–s previously issued guidance of 1,200 MMcf/d to 1,220 MMcf/d for the second quarter of 2011.
North America – Oil Sands Mining and Upgrading
Production averaged 3,615 bbl/d for the six months ended June 30, 2011, decreasing by 96% from 93,508 bbl/d for the six months ended June 30, 2010. There was no production for the second quarter of 2011, compared to 99,950 bbl/d in the second quarter of 2010 and 7,269 bbl/d in the prior quarter. The decrease in production for the six months ended June 30, 2011 reflected the suspension of production of synthetic crude oil on January 6, 2011 following the occurrence of a fire at Horizon–s primary upgrading coking plant.
As at August 3, 2011, all necessary regulatory and operating approvals to recommence operations were received. Final mechanical, testing and commissioning activities are ongoing and production is scheduled for the third quarter of 2011.
North Sea
North Sea crude oil production for the six months ended June 30, 2011 decreased 10% to 33,480 bbl/d from 37,276 bbl/d for the six months ended June 30, 2010. Second quarter 2011 North Sea crude oil production decreased 13% to 32,866 bbl/d from 37,669 bbl/d for the second quarter of 2010, and decreased 4% from 34,101 bbl/d for the prior quarter. The decrease in production volumes from the comparable periods in 2010 was due to natural field declines. Production in the second quarter of 2011 exceeded the Company–s previously issued guidance of 29,000 bbl/d to 32,000 bbl/d due to strong performance from the Olive Oyl well brought online in December 2010 and strong base performance of the Ninian Field.
Offshore Africa
Offshore Africa crude oil production decreased 22% to 23,400 bbl/d for the six months ended June 30, 2011 from 29,892 bbl/d for the six months ended June 30, 2010. Second quarter crude oil production averaged 21,334 bbl/d, decreasing 29% from 29,842 bbl/d for the second quarter of 2010 and 16% from 25,488 bbl/d for the prior quarter. The decrease in production volumes from the second quarter of 2010 was primarily due to the temporary suspension of production at the Olowi Field, Gabon as a result of the failure in the supporting mechanism for production and gas lift flowlines and the main power line. Olowi production was reinstated at Platform C during the second quarter. The midwater arch was re-secured in the second quarter and after a full evaluation and appropriate testing, it was determined it can be used to restart production from Platforms A and B in the third quarter of 2011. Production in the second quarter of 2011 was at the low end of the Company–s previously issued guidance of 21,000 bbl/d to 24,000 bbl/d.
Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when title transfers to the customer and delivery has taken place. Revenue has not been recognized on crude oil volumes that were stored in various tanks, pipelines, or floating production, storage and offloading vessels, as follows:
North America
North America realized crude oil prices increased 11% to average $69.92 per bbl for the six months ended June 30, 2011 from $63.15 per bbl for the six months ended June 30, 2010. North America realized crude oil prices averaged $77.62 per bbl for the second quarter of 2011, an increase of 29% compared to $60.35 per bbl for the second quarter of 2010 and an increase of 25% compared to $62.21 per bbl for the prior quarter. The increase in prices for the six months ended June 30, 2011 from the comparable period in 2010 was primarily a result of higher WTI benchmark pricing, partially offset by the widening WCS Heavy Differential and the impact of a stronger Canadian dollar relative to the US dollar. The increase in prices for the three months ended June 30, 2011 was primarily a result of the higher benchmark WTI pricing and narrowing WCS Heavy Differential, partially offset by the impact of the stronger Canadian dollar relative to the US dollar.
The Company continues to focus on its crude oil blending marketing strategy, and in the second quarter of 2011 contributed approximately 155,000 bbl/d of heavy crude oil blends to the WCS stream.
In the first quarter of 2011, the Company announced that it had entered into a partnership agreement with North West Upgrading Inc. to move forward with detailed engineering regarding the construction and operation of a bitumen refinery near Redwater, Alberta. In addition, the partnership has entered into an agreement to process bitumen supplied by the Government of Alberta under the Alberta Royalty Framework–s Bitumen Royalty In Kind initiative. Project development is dependent upon completion of detailed engineering and final project sanction by the respective parties. Board sanction is currently targeted for the latter half of 2011 or the first half of 2012.
North America realized natural gas prices decreased 17% to average $3.76 per Mcf for the six months ended June 30, 2011 from $4.51 per Mcf for the six months ended June 30, 2010. North America realized natural gas prices averaged $3.76 per Mcf for the second quarter of 2011, a decrease of 2% compared to $3.85 per Mcf for the second quarter of 2010, and were comparable to the prior quarter. The decrease in natural gas prices from the six months ended June 30, 2010 was primarily related to the impact of strong supply from US shale projects and continued weak demand from the industrial sector, together with the impact of a stronger Canadian dollar.
Comparisons of the prices received in North America Exploration and Production by product type were as follows:
North Sea
North Sea realized crude oil prices increased 35% to average $107.75 per bbl for the six months ended June 30, 2011 from $79.95 per bbl for the six months ended June 30, 2010. Realized crude oil prices averaged $112.32 per bbl for the second quarter of 2011, an increase of 42% from $79.30 per bbl for the second quarter of 2010, and an increase of 10% from $102.51 per bbl for the prior quarter. The increase in realized crude oil prices in the North Sea from the comparable periods in 2010 was primarily the result of increased Brent benchmark pricing, partially offset by the impact of the stronger Canadian dollar.
Offshore Africa
Offshore Africa realized crude oil prices increased 29% to average $102.56 per bbl for the six months ended June 30, 2011 from $79.25 per bbl for the six months ended June 30, 2010. Realized crude oil prices averaged $110.42 per bbl for the second quarter of 2011, an increase of 39% from $79.21 per bbl for the second quarter of 2010, and an increase of 14% from $97.09 per bbl in the prior quarter. The increase in realized crude oil prices in Offshore Africa from the comparable periods in 2010 was primarily the result of increased Brent benchmark pricing, partially offset by the impact of the stronger Canadian dollar.
North America
North America royalties for the six months ended June 30, 2011 compared to 2010 reflected benchmark commodity prices.
Crude oil and NGLs royalties averaged approximately 17% of product sales for the second quarter of 2011 and 2010, compared to 19% for the prior quarter. The decrease in royalties from the prior quarter was due to crude oil royalty adjustments recorded in the prior quarter and an increase in capital expenditures at Primrose. Crude oil and NGLs royalties per bbl are anticipated to average 16% to 19% of product sales for 2011.
Natural gas royalties averaged approximately 6% of product sales for the second quarter of 2011 and 2010, compared to 3% for the prior quarter. The increase in natural gas royalty rates from the prior quarter was primarily due to gas cost allowance adjustments recorded in the current quarter. Natural gas royalties are anticipated to average 3% to 5% of product sales for 2011.
Offshore Africa
Under the terms of the various Production Sharing Contracts, royalty rates fluctuate based on realized commodity pricing, capital costs, and the timing of liftings from each field. Royalty rates as a percentage of product sales averaged approximately 1% for the second quarter of 2011 compared to 5% for the second quarter of 2010 and 9% for the prior quarter. The decrease in royalties from the second quarter of 2010 and the prior quarter was due to crude oil royalty adjustments related to the Baobab and Espoir Fields. Offshore Africa royalty rates are anticipated to increase in 2011 to average 10% to 12% of product sales, from 7% in 2010, as a result of payout of the Baobab Field during the second quarter of 2011.
North America
North America crude oil and NGLs production expense for the six months ended June 30, 2011 was comparable to the six months ended June 30, 2010. North America crude oil and NGLs production expense for the second quarter of 2011 increased 9% to $12.86 per bbl from $11.75 per bbl for the second quarter of 2010 and increased 5% from $12.28 per bbl for the prior quarter. The increase in production expense per barrel from the second quarter of 2010 and the prior quarter was a result of higher overall service costs relating to heavy crude oil production and the impact of the forest fires in North Central Alberta and flooding in South East Saskatchewan. The increase in production expense per barrel from the prior quarter was also due to the timing of thermal steam cycles. North America crude oil and NGLs production expense is anticipated to average $12.00 to $13.00 per bbl for 2011.
North America natural gas production expense for the six months ended June 30, 2011 averaged $1.12 per Mcf and was comparable to the six months ended June 30, 2010. North America natural gas production expense for the second quarter of 2011 averaged $1.09 per Mcf and increased 6% compared to $1.03 per Mcf for the second quarter of 2010. Natural gas production expense for the second quarter of 2011 increased from the comparable period in 2010 due to acquisitions of natural gas producing properties that have higher operating costs per Mcf than the Company–s existing properties. These costs are expected to decline once the acquisitions are fully integrated into the Company–s operations. Natural gas production expense decreased 6% from $1.16 per Mcf for the prior quarter, as the prior quarter reflected normal seasonal costs associated with winter access and colder weather. North America natural gas production expense is anticipated to average $1.05 to $1.15 per Mcf for 2011.
North Sea
North Sea crude oil production expense for the six months ended June 30, 2011 increased 39% to $32.46 per bbl from $23.35 per bbl for the six months ended June 30, 2010. North Sea crude oil production expense for the second quarter of 2011 increased 60% to $34.20 per bbl from $21.35 per bbl for the second quarter of 2010 and increased 12% from $30.46 per bbl for the prior quarter. Production expense increased on a per barrel basis from the comparable periods in 2010 and the prior quarter due to lower volumes on relatively fixed costs and the inclusion of one-time third party cost recoveries in the second quarter of 2010. Production expense is anticipated to average $35.00 to $39.00 per bbl for 2011.
Offshore Africa
Offshore Africa crude oil production expense increased 24% to $20.04 per bbl from $16.11 per bbl for the six months ended June 30, 2010. Offshore Africa crude oil production expense for the second quarter of 2011 averaged $21.36 per bbl, an increase of 17% compared to $18.33 per bbl for the second quarter of 2010 and an increase of 12% compared to $19.13 per bbl for the prior quarter. Production expense increased on a per barrel basis from the comparable periods due to the timing of liftings for each field, and due to lower volumes on relatively fixed costs. Production expense for the second quarter of 2011 was higher than the prior quarter due to the timing of liftings for each field. Production expense is anticipated to average $20.00 to $23.00 per bbl for 2011.
Depletion, depreciation and amortization expense increased for the six months ended June 30, 2011 compared to 2010 due to higher production in North America and an increase in the estimated future costs to develop the Company–s proved and developed reserves. Depletion, depreciation and amortization expense for the three months ended June 30, 2011 was comparable to the three months ended June 30, 2010 and the prior quarter on a per barrel basis.
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time.
OPERATING HIGHLIGHTS – OIL SANDS MINING AND UPGRADING
OPERATIONS UPDATE
On January 6, 2011, the Company suspended SCO production at its Oil Sands Mining and Upgrading operations due to a fire in the primary upgrading coking plant. As at August 3, 2011, all necessary regulatory and operating approvals to recommence operations were received. Final mechanical, testing and commissioning activities are ongoing and production is scheduled for the third quarter of 2011.
Realized SCO sales prices averaged $82.93 per bbl for the six months ended June 30, 2011, an increase of 7% compared to $77.29 per bbl for the six months ended June 30, 2010. Realized SCO sales prices for the six months ended June 30, 2011 reflected the prices reported in the first quarter of 2011 due to the impact of suspension of production of synthetic crude oil in January 2011.
PRODUCTION COSTS
The following tables are reconciled to the Oil Sands Mining and Upgrading production costs disclosed in note 17 to the Company–s unaudited interim consolidated financial statements.
Total cash production costs averaged $45.69 per bbl for the six months ended June 30, 2011 compared to $37.39 per bbl for the six months ended June 30, 2010. Cash production costs for the six months ended June 30, 2011 reflected the cash production costs reported in the first quarter of 2011 due to the impact of the suspension of production of synthetic crude oil in January 2011.
Depletion, depreciation and amortization expense for the six months ended June 30, 2011 decreased from the six months ended June 30, 2010 primarily due to the impact of the suspension of production of synthetic crude oil in January 2011.
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time.
Administration expense for the six and three months ended June 30, 2011 increased from the comparable periods in 2010 and the prior quarter primarily due to higher staffing related costs.
SHARE-BASED COMPENSATION EXPENSE
The Company–s stock option plan provides current employees with the right to receive common shares or a direct cash payment in exchange for options surrendered.
The Company recorded a $60 million share-based compensation recovery for the six months ended June 30, 2011 primarily as a result of remeasurement of the fair value of outstanding options at the end of the period, offset by normal course graded vesting of options granted in prior periods and the impact of vested options exercised or surrendered during the period. For the six months ended June 30, 2011, the Company recovered $2 million in share-based compensation previously capitalized to Oil Sands Mining and Upgrading (June 30, 2010 – capitalized $8 million).
For the six months ended, June 30, 2011, the Company paid $11 million for stock options surrendered for cash settlement (June 30, 2010 – $38 million).
Gross interest and other financing costs for the three and six months ended June 30, 2011 decreased from the comparable period in 2010 due to the impact of a stronger Canadian dollar on US dollar denominated debt, partially offset by higher variable interest rates. Gross interest and other financing costs increased compared to the prior quarter due to higher overall debt levels, partially offset by the impact of a stronger Canadian dollar on US dollar denominated debt.
The Company–s average effective interest rates for the three and six months ended June 30, 2011 were comparable to 2010 and the prior quarter.
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its commodity price, foreign currency and interest rate exposures. These derivative financial instruments are not intended for trading or speculative purposes.
Complete details related to outstanding derivative financial instruments at June 30, 2011 are disclosed in note 15 to the Company–s unaudited interim consolidated financial statements.
The Company recorded a net unrealized gain of $64 million ($48 million after-tax) on its risk management activities for the six months ended June 30, 2011, including an unrealized gain of $118 million ($87 million after-tax) for the second quarter of 2011 (March 31, 2011 – unrealized loss of $54 million, $39 million after-tax; June 30, 2010 – unrealized gain of $86 million, $67 million after-tax), primarily due to changes in crude oil and natural gas forward pricing and the reversal of prior period unrealized gains and losses.
FOREIGN EXCHANGE
The net unrealized foreign exchange gain for the six months ended June 30, 2011 was primarily due to the strengthening of the Canadian dollar with respect to US dollar debt. The net unrealized gain for each of the periods presented included the impact of cross currency swaps (six months ended June 30, 2011 – unrealized loss of $64 million, March 31, 2011 – unrealized loss of $48 million, June 30, 2010 – unrealized gain of $32 million). The net realized foreign exchange loss for the six months ended June 30, 2011 was primarily due to foreign exchange rate fluctuations on settlement of working capital items denominated in US dollars or UK pounds sterling. The Canadian dollar ended the second quarter at US$1.0370 (March 31, 2011- US $1.0290; December 31, 2010 – US$1.0054; June 30, 2010 – US$0.9429).
Taxable income from the Exploration and Production business in Canada is primarily generated through partnerships, with the related income taxes payable in periods subsequent to the current reporting period. North America current and deferred income taxes have been provided on the basis of this corporate structure. In addition, current income taxes in each business segment will vary depending on available income tax deductions related to the nature, timing and amount of capital expenditures incurred in any particular year.
In June 2011, the Canadian Federal government tabled a budget that proposed several taxation changes that could impact the Company. These proposed changes include:
To date, no legislation related to the budget proposals has been released.
In March 2011, the UK government substantively enacted an increase to the supplementary income tax rate charged on profits from UK North Sea crude oil and natural gas production increasing the combined corporate and supplementary income tax rate from 50% to 62%. This resulted in an increase to the overall effective corporate tax rate applicable to net operating income from oil and gas activities to 62% from 50% for non-PRT paying fields and 81% from 75% for PRT paying fields, after allowing for deductions for capital and abandonment expenditures. As a result of the income tax rate change, the Company–s deferred income tax liability was increased by $104 million as at March 31, 2011.
The Company is subject to income tax reassessments arising in the normal course. The Company does not believe that any liabilities ultimately arising from these reassessments will be material.
For 2011, based on budgeted prices and the current availability of tax pools, the Company expects to incur current income tax expense of $300 million to $400 million in Canada and $460 million to $500 million in the North Sea and Offshore Africa.
The Company–s strategy is focused on building a diversified asset base that is balanced among various products. In order to facilitate efficient operations, the Company concentrates its activities in core regions where it can dominate the land base and infrastructure. The Company focuses on maintaining its land inventories to enable the continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By dominating infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production costs.
Net capital expenditures for the six months ended June 30, 2011 were $3,099 million compared to $2,652 million for the six months ended June 30, 2010. Net capital expenditures for the second quarter of 2011 were $1,405 million compared to $1,576 million for the second quarter of 2010 and $1,694 million for the prior quarter.
The increase in capital expenditures from the six months ended June 30, 2010 was primarily due to an increase in well drilling and completion expenditures related to the Company–s heavy oil drilling program, an increase in the Company–s abandonment program and costs associated with the coker rebuild and collateral damage resulting from the coker fire. The decrease in capital expenditures in the second quarter of 2011 from the prior quarter was primarily due to lower seasonal spending on drilling activities and related facilities, partially offset by higher costs associated with the coker rebuild and collateral damage.
North America
North America, excluding Oil Sands Mining and Upgrading, accounted for approximately 73% of the total capital expenditures for the six months ended June 30, 2011 compared to approximately 84% for the six months ended June 30, 2010.
During the second quarter of 2011, the Company targeted 10 net natural gas wells, including 6 wells in Northeast British Columbia and 4 wells in Northwest Alberta. The Company also targeted 182 net crude oil wells. The majority of these wells were concentrated in the Company–s Northern Plains region where 134 primary heavy crude oil wells, 7 Pelican Lake heavy crude oil wells and 37 bitumen (thermal oil) wells were drilled. Another 4 wells targeting light crude oil were drilled outside the Northern Plains region.
As part of the phased expansion of its In Situ Oil Sands Assets, the Company is continuing to develop its Primrose thermal projects. Overall Primrose thermal production for the second quarter of 2011 averaged approximately 106,000 bbl/d, compared to approximately 96,000 bbl/d for the second quarter of 2010 and approximately 98,000 bbl/d for the prior quarter.
The next planned phase of the Company–s In Situ Oil Sands Assets expansion is the Kirby South Phase 1 Project. Currently the Company is proceeding with the detailed engineering and design work. During the third quarter of 2010, the Company received final regulatory approval for Phase 1 of the Project. During the fourth quarter of 2010, the Company–s Board of Directors sanctioned Kirby South Phase 1. Construction has commenced, with first steam targeted in 2013.
Development of the tertiary recovery conversion projects at Pelican Lake continued in the second quarter of 2011. Drilling included 7 horizontal wells during the quarter. Response from the polymer flood project continues to be positive, but delayed from the original plan. Pelican Lake production averaged approximately 35,000 bbl/d for the second quarter of 2011, compared to 37,000 bbl/d for the second quarter of 2010 and 39,000 bbl/d for the prior quarter, due to the temporary impact of the forest fires in North Central Alberta.
For the third quarter of 2011, the Company–s overall planned drilling activity in North America is expected to be comprised of 24 net natural gas wells and 367 net crude oil wells excluding stratigraphic and service wells.
Oil Sands Mining and Upgrading
Phase 2/3 spending during the second quarter of 2011 continued to be focused on construction of the third Ore Preparation Plant and associated hydro-transport, additional product tankage, the butane treatment unit and the sulphur recovery unit. Commissioning of the Ore Preparation Plant and associated hydro-transport is currently targeted early in the fourth quarter of 2011.
On January 6, 2011, the Company suspended SCO production at its Oil Sands Mining and Upgrading operations due to a fire in the primary upgrading coking plant. As at August 3, 2011, all necessary regulatory and operating approvals to recommence operations were received. Final mechanical, testing and commissioning activities are ongoing and production is scheduled for the third quarter of 2011.
During the first quarter of 2011, the Company recognized a Horizon asset impairment provision of $396 million, net of accumulated depletion and depreciation, related to the property damage resulting from the fire in the primary upgrading coking plant. As the Company believes that its insurance coverage is adequate to mitigate all significant property damage related losses, estimated insurance proceeds receivable of $396 million were also recognized offsetting such property damage. The final Horizon asset impairment provision and related insurance recoveries are subject to revision upon recommencement of operations and the determination of final costs to restore plant operating capacity. Accordingly, actual results may differ significantly from the amounts currently recognized.
The Company also maintains business interruption insurance to reduce operating losses related to its ongoing operations. During the second quarter of 2011, the Company recognized business interruption insurance recoveries of $136 million, based on interim payments and claims processed to date. Additional business interruption insurance recoveries related to the second and third quarters will be recognized at such time as additional interim payments are processed and as the final terms of the insurance settlement are determined.
North Sea
During the second quarter of 2011, the Company continued workover and drilling operations on the Ninian South Platform.
In March 2011, the UK government substantively enacted an increase to the corporate income tax rate charged on profits from UK North Sea crude oil and natural gas production from 50% to 62%. This resulted in an increase to the overall corporate tax rate applicable to net operating income from oil and gas activities to 62% for non-PRT paying fields and 81% for PRT paying fields, after allowing for deductions for capital and abandonment expenditures.
As a result of the increase in the corporate income tax rate, the Company–s development activities in the North Sea will be reduced. The Company is now maintaining only one drilling string in the North Sea, down from the two originally planned. The planned drilling activity at Murchison during 2011 was cancelled. The Company will continue to high grade all North Sea prospects for potential future development opportunities.
Offshore Africa
During the second quarter of 2011, production at the Olowi Field was temporarily suspended as a result of the failure of a midwater arch system that provides support for production and gas lift flowlines and the main power line. All necessary safety and environmental precautions were undertaken to temporarily cease operations.
Olowi production was reinstated at Platform C during the second quarter. The midwater arch was re-secured in the second quarter and after a full evaluation and appropriate testing, it was determined it can be used to restart production from Platforms A and B. However damage to the communication cable was not repairable. As such, a new communication system is being procured with an expected completion in the third quarter of 2011, at which time production from the two platforms will be restarted.
At June 30, 2011, the Company–s capital resources consisted primarily of cash flow from operations, available bank credit facilities and access to debt capital markets. Cash flow from operations is dependent on factors discussed in the “Risks and Uncertainties” section of the Company–s December 31, 2010 annual MD&A. The Company–s ability to renew existing bank credit facilities and raise new debt is also dependent upon these factors, as well as maintaining an investment grade debt rating and the condition of capital and credit markets. The Company continues to believe that its internally generated cash flow from operations supported by the implementation of its on-going hedge policy, the flexibility of its capital expenditure programs supported by its multi-year financial plans, its existing bank credit facilities, and its ability to raise new debt on commercially acceptable terms, will provide sufficient liquidity to sustain its operations in the short, medium and long term and support its growth strategy.
During the second quarter of 2011, the $2,230 million revolving syndicated credit facility was increased to $3,000 million and extended to June 2015. Each of the $3,000 million and $1,500 million facility is extendible annually for one year periods at the mutual agreement of the Company and the lenders. At June 30, 2011, the Company had $2,800 million of available credit under its bank credit facilities. Subsequent to June 30, 2011, US $400 million of US dollar denominated debt securities bearing interest at 6.7% were repaid. During the fourth quarter of 2010, the Company repaid $400 million of the medium-term notes bearing interest at 5.50%.
The Company believes that its capital resources are sufficient to compensate for any short-term cash flow reduction arising from Horizon, and accordingly, the Company–s targeted North America capital program has been increased for 2011.
Long-term debt was $8,624 million at June 30, 2011, resulting in a debt to book capitalization ratio of 29% (March 31, 2011- 29%; December 31, 2010 – 29%; June 30, 2010 – 32%). This ratio is below the 35% to 45% internal range utilized by management. This range may be exceeded in periods when a combination of capital projects, acquisitions, and lower commodity prices occur. The Company may be below the low end of the targeted range when cash flow from operating activities is greater than current investment activities. The Company remains committed to maintaining a strong balance sheet, adequate available liquidity and flexible capital structure. The Company has hedged a portion of its crude oil production for 2011 at prices that protect investment returns to ensure ongoing balance sheet strength and the completion of its capital expenditure programs. Further details related to the Company–s long-term debt at June 30, 2011 are discussed in note 7 to the Company–s unaudited interim consolidated financial statements.
The Company–s commodity hedging program reduces the risk of volatility in commodity prices and supports the Company–s cash flow for its capital expenditures programs. This program currently allows for the hedging of up to 60% of the near 12 months budgeted production and up to 40% of the following 13 to 24 months estimated production. For the purpose of this program, the purchase of put options is in addition to the above parameters. As at June 30, 2011, in accordance with the policy, approximately 11% of budgeted crude oil volumes were hedged using collars for 2011. Further details related to the Company–s commodity related derivative financial instruments outstanding at June 30, 2011 are discussed in note 15 to the Company–s unaudited interim consolidated financial statements.
Share capital
As at June 30, 2011, there were 1,097,078,000 common shares outstanding and 60,691,000 stock options outstanding. As at August 2, 2011, the Company had 1,097,205,000 common shares outstanding and 60,333,000 stock options outstanding.
On March 1, 2011, the Company–s Board of Directors approved an increase in the annual dividend to be paid by the Company to $0.36 per common share for 2011. The increase represents a 20% increase from 2010, recognizing the stability of the Company–s cash flow and providing a return to Shareholders. The dividend policy undergoes a periodic review by the Board of Directors and is subject to change.
On March 31, 2011, the Company announced a Normal Course Issuer Bid to purchase, through the facilities of the TSX and the NYSE, during the 12 month period commencing April 6, 2011 and ending April 5, 2012, up to 27,406,131 common shares or 2.5% of the common shares of the Company outstanding at March 25, 2011. As at August 3, 2011, no common shares had been purchased under this Normal Course Issuer Bid.
In 2010, the Company announced a Normal Course Issuer Bid to purchase, through the facilities of the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange (“NYSE”), during the 12 month period commencing April 6, 2010 and ending April 5, 2011, up to 27,163,940 common shares or 2.5% of the common shares of the Company outstanding at March 17, 2010. A total of 2,000,000 common shares were purchased for cancellation under this Normal Course Issuer Bid at an average price of $33.77 per common share, for a total cost of $68 million.
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into various commitments that will have an impact on the Company–s future operations. As at June 30, 2011, no entities were consolidated under the Standing Interpretations Committee 12, “Consolidation – Special Purpose Entities”. The following table summarizes the Company–s commitments as at June 30, 2011:
LEGAL PROCEEDINGS AND OTHER CONTINGENCIES
The Company is defendant and plaintiff in a number of legal actions arising in the normal course of business. In addition, the Company is subject to certain contractor construction claims. The Company believes that any liabilities that might arise pertaining to any such matters would not have a material effect on its consolidated financial position.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
The Company has identified, developed and tested systems and accounting and reporting processes and changes required to capture data required for IFRS accounting and reporting, including 2010 requirements to capture both Canadian GAAP and IFRS data.
INTERNATIONAL FINANCIAL REPORTING STANDARDS
In February 2008, the CICA–s Accounting Standards Board confirmed that Canadian publicly accountable enterprises would be required to adopt IFRS as issued by the IASB in place of Canadian GAAP effective January 1, 2011.
The Company has completed its transition to IFRS. The 2011 fiscal year is the first year in which the Company has prepared its consolidated financial statements in accordance with IFRS as issued by the IASB. The interim consolidated financial statements for the six months ended June 30, 2011 have been prepared in accordance with IFRS applicable to the preparation of interim financial statements, including International Accounting Standard (“IAS”) 34, “Interim Financial Reporting” and IFRS 1, “First-time Adoption of International Financial Reporting Standards”.
The accounting policies adopted by the Company under IFRS are set out in note 1 to the interim consolidated financial statements for the six months ended June 30, 2011. Note 18 to the interim consolidated financial statements discloses the impact of the transition to IFRS on the Company–s reported financial position, earnings and cash flows, including the nature and effect of certain transition elections and significant changes in accounting policies from those used in the Company–s Canadian GAAP consolidated financial statements for 2010.
ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED
The Company is required to adopt IFRS 9, “Financial Instruments”, effective January 1, 2013, with earlier adoption permitted. IFRS 9 replaces existing requirements included in IAS 39, “Financial Instruments – Recognition and Measurement”. The new standard replaces the multiple classification and measurement models for financial assets and liabilities with a new model that has only two categories: amortized cost and fair value through profit and loss. Under IFRS 9, fair value changes due to credit risk for liabilities designated at fair value through profit and loss would generally be recorded in other comprehensive income.
In May 2011, the IASB issued the following new accounting standards, which are required to be adopted effective January 1, 2013:
In June 2011, the IASB issued amendments to IAS 1 “Presentation of Financial Statements” that require items of other comprehensive income (OCI) that may be reclassified to net earnings to be grouped together. The amendments also require that items in OCI and net earnings be presented as either a single statement or two consecutive statements. The standard is effective for fiscal years beginning on or after July 1, 2012.
The Company is currently assessing the impact of these new and amended standards on its consolidated financial statements.
CRITICAL ACCOUNTING ESTIMATES AND CHANGE IN ACCOUNTING POLICIES
The preparation of financial statements requires the Company to make judgements, assumptions and estimates in the application of IFRS that have a significant impact on the financial results of the Company. Actual results could differ from those estimates, and those differences may be material.
Critical accounting estimates are reviewed by the Company–s Audit Committee annually. The Comp