CALGARY, ALBERTA — (Marketwire) — 05/03/12 — Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ)
Commenting on first quarter results, Canadian Natural–s Vice-Chairman John Langille stated, “Our balanced asset base and production mix are key components to our strategy of creating long term shareholder value throughout the commodity price cycles. We exited Q1/12 in a strong financial position and continue to have a high degree of flexibility in our capital allocation. This drives our ability to transition to more sustainable, longer life production delivered from our existing asset base. The strength of our portfolio is evident as we target to grow production from Q4/11 to Q4/12 by 10% while spending within cash flow and allocating more than half our 2012 capital budget to projects for future production.”
Steve Laut, President of Canadian Natural continued, “Production was successfully re-started at Horizon on March 13, 2012. The third ore preparation plant and associated hydro-transport unit were fully integrated into operations in the quarter and contributed to solid production of approximately 111,500 bbl/d in April. Our thermal in situ operations are heading into a production cycle following completion of the steaming cycle and we are targeting a strong ramp up in production through to the end of the year. In addition, our primary heavy crude oil achieved record quarterly production and Canadian light crude oil and NGLs will continue to be strong drivers of value growth in 2012.”
– Total crude oil and NGLs production averaged 395,461 bbl/d in Q1/12 representing an increase of 11% over Q1/11 and a decrease of 11% from Q4/11. The increase in production over Q1/11 reflects the successful results of primary heavy crude oil and light crude oil drilling programs and increased production from Horizon partially offset by the timing of steaming cycles in Bitumen (“thermal in situ”). The decrease in production from Q4/11 was a result of the temporary suspension of production at Horizon. On February 5, 2012 production at Horizon was suspended for unplanned maintenance on the fractionating unit. Production for the quarter exceeded previously issued guidance as a result of resuming production on March 13, 2012, earlier than originally anticipated.
– Total natural gas production for Q1/12 was 1,302 MMcf/d representing an increase of 4% over Q1/11 and 2% over Q4/11. The increase in production reflects the impact of natural gas producing properties acquired during 2011 and strong results from the Company–s modest, liquids rich drilling program offset by natural declines.
– Canadian Natural generated quarterly cash flow from operations of $1.28 billion compared to $1.07 billion in Q1/11 and $2.16 billion in Q4/11. The increase in cash flow from Q1/11 was primarily related to higher sales volumes from the Company–s North America crude oil and NGLs and oil sands mining operations. The decrease in cash flow from Q4/11 was primarily related to lower synthetic crude oil (“SCO”) sales volumes, lower crude oil and NGLs netbacks and lower natural gas prices.
– AECO benchmark natural gas prices were down 27% in Q1/12 from Q4/11. This reduction in pricing was responsible for approximately $75 million less after-tax cash flow in Q1/12. The lower current strip AECO natural gas prices for full year 2012 when compared to original budget targets an after-tax cash flow reduction of approximately $550 million. As a result, the Company has reduced natural gas capital expenditures by $190 million from original budget and has reduced full year targeted drilling to 36 net wells.
– Adjusted net earnings from operations for the quarter was $300 million, compared to adjusted net earnings of $228 million in Q1/11 and $972 million in Q4/11. Changes in adjusted net earnings reflect the changes in cash flow from operations.
– North America light crude oil and NGLs quarterly production increased 19% compared to Q1/11 and increased 7% compared to Q4/11 as a result of a successful light oil drilling program and increased liquid recoveries from Septimus following the completion of a tie in to a deep cut facility.
– Primary heavy crude oil production increased 24% compared to Q1/11 and 8% compared to Q4/11, achieving record quarterly production exceeding 120,000 bbl/d. Canadian Natural targets to drill approximately 815 net primary heavy crude oil wells in 2012 and increase production by 19% over 2011, 3% above original expectations primarily due to better than expected results from Woodenhouse. Woodenhouse is a new non-traditional primary heavy crude oil area located 75 kilometers north of Pelican Lake.
– At Horizon, the third ore preparation plant (“OPP”) and associated hydro-transport unit were successfully integrated into operations in the quarter. The third OPP is expected to increase production reliability going forward by allowing the Company to maintain steady feedstock to the upgrader with two of the three OPPs continually on stream. SCO production in April 2012 averaged approximately 111,500 bbl/d.
– The WCS heavy crude oil differential as a percent of WTI averaged 21% in Q1/12. The WCS heavy differential widened in Q1/12 from Q4/11 as a result of planned and unplanned maintenance at key refineries in the United States and Canada. The WCS heavy crude oil differential as a percent of WTI widened to 29% in March and 32% in April. As expected, the differential for May narrowed to 19% and indications in June are for further tightening to approximately 14% as refineries come back on stream.
– Subsequent to Q1/12, Toronto Stock Exchange accepted notice of Canadian Natural–s renewal of its Normal Course Issuer Bid through the facilities of Toronto Stock Exchange and the New York Stock Exchange. The notice provides that Canadian Natural may, during the 12 month period commencing April 9, 2012 and ending April 8, 2013, purchase for cancellation on Toronto Stock Exchange and the New York Stock Exchange up to 55,027,447 shares.
– Canadian Natural purchased 692,200 common shares in the quarter for cancellation at a weighted average price of $33.11 per common share. Subsequent to the quarter, the Company purchased a further 521,100 common shares at a weighted average price of $32.21 per common share.
– Declared a quarterly cash dividend on common shares of $0.105 per common share payable July 1, 2012.
GOVERNANCE UPDATE
As part of the Company–s commitment to good governance practices, the Board of Directors has appointed Ambassador Gordon D. Giffin as independent lead Director concurrently with the Company–s Annual and Special Meeting of Shareholders on May 3, 2012.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural focuses its activities in core regions where it can own a substantial land base and associated infrastructure. Land inventories are maintained to enable continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By owning associated 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; light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, Bitumen (“thermal in situ”), SCO (herein collectively referred to as “crude oil”), natural gas and NGLs. A large diversified project portfolio enables the effective allocation of capital to higher return opportunities.
OPERATIONS REVIEW
– North America crude oil and NGLs production were within previously issued guidance for the quarter as a result of efficient and effective operations. Production averaged 305,613 bbl/d in Q1/12 representing an increase of 5% from Q1/11 and Q4/11. The increase in production was a result of successful primary heavy and light crude oil drilling programs.
– Primary heavy crude oil production increased 24% compared to Q1/11 and 8% compared to Q4/11, achieving record quarterly production exceeding 120,000 bbl/d. Canadian Natural targets to drill approximately 815 net primary heavy crude oil wells in 2012 and increase production by 19% over 2011, 3% above original expectations primarily due to better than expected results from Woodenhouse. Woodenhouse is a new non-traditional primary heavy crude oil area located 75 kilometers north of Pelican Lake.
– North America light crude oil and NGLs quarterly production increased 19% compared to Q1/11 and increased 7% compared to Q4/11 as a result of a successful light oil drilling program and increased liquid recoveries from Septimus following the completion of a tie in to a deep cut facility. North America light crude oil and NGLs is a significant part of Canadian Natural–s balanced portfolio, averaging approximately 66,000 bbl/d in the quarter.
– At Pelican Lake, reservoir performance continues to be positive. The Company is constructing a 25,000 bbl/d battery and targets to drill eight injectors and 78 producers in 2012. The Company targets to ultimately recover 561 million barrels (363 million barrels of proved plus probable reserves and 198 million barrels of contingent resources) of additional crude oil from this world class crude oil pool.
– As expected, thermal in situ production averaged approximately 80,000 bbl/d in Q1/12 as a result of the timing of steaming cycles. Production is targeted to ramp up in the second quarter as pads re-enter the production cycle. The Company targets to increase production by 8% in 2012 over 2011.
– Canadian Natural has a robust portfolio of steam assisted gravity drainage (“SAGD”) projects with the potential to grow thermal in situ production to approximately 480,000 bbl/d of capacity. Each project will be used as a template for the projects that follow, allowing the Company to continually refine development and optimize performance. The Company targets to add 40,000 to 60,000 bbl/d of production every two to three years through the development of these projects.
— Kirby South Phase 1 remains on cost and on schedule with first steam-in targeted for late 2013. Drilling is progressing on the fourth of seven pads with wells confirming geological expectations. The total project was 42% complete at the end of the quarter.
— Construction preparation work is underway on Kirby North Phase 1 including construction of the main access road and clearing of the plant site. First steam-in is targeted for 2016.
— The regulatory approval application for Grouse was submitted in the quarter with first steam-in targeted for 2017.
— Canadian Natural has an active stratigraphic (“strat”) test well drilling program to delineate the reservoir characteristics for future projects. The Company drilled 355 strat test and observation wells in the quarter.
– In Q2/12, the Company plans to drill 44 net thermal in situ wells and 182 net crude oil wells, excluding strat test and service wells.
– North America crude oil and NGLs operating costs increased to $15.40/bbl from $12.28/bbl in Q1/11 and $14.32/bbl in Q4/11. The increase was primarily due to higher primary heavy crude oil operating costs as a result of increased trucking costs, facility treating constraints (Lindbergh expansion targeted for Q3/12), drilling more wells than budgeted in Q1/12, seasonality and the impact of greater than forecasted production from Woodenhouse. Notwithstanding these Q1/12 costs, 2012 full year operating cost guidance for North America crude oil and NGLs remains at $11.00/bbl to $13.00/bbl.
– North America natural gas production for the quarter averaged 1,281 MMcf/d representing an increase of 5% from Q1/11 and an increase of 2% from Q4/11. The increase in production was a result of natural gas producing properties acquired in 2011 and strong results from the Company–s modest, liquids rich drilling program offset by natural declines.
– AECO benchmark natural gas prices were down 27% in Q1/12 from Q4/11. This reduction in pricing was responsible for approximately $75 million less after-tax cash flow in Q1/12. The lower current strip AECO natural gas prices for full year 2012 when compared to original budget targets an after-tax cash flow reduction of approximately $550 million. As a result, the Company has reduced natural gas capital expenditures by $190 million from original budget and has reduced full year targeted drilling to 36 net wells.
– In Q1/12 the Company has shut-in approximately 16 MMcf/d of natural gas in addition to the approximately 20 MMcf/d shut-in in Q4/11. The Company has a strategic plan to shut-in certain additional natural gas volumes of approximately 22 MMcf/d if natural gas prices remain below economic thresholds in those areas.
– At Septimus, the plant expansion remains on track and on budget. The expansion will increase sales capacity to 110 MMcf/d and approximately 11,000 bbl/d of liquids. The Company targets to drill 10 net natural gas wells in 2012, reflecting a reduction of 7 net natural gas wells from the previous forecast.
– North America natural gas operating costs increased to $1.33/Mcf from $1.16/Mcf in Q1/11 and $1.12/Mcf in Q4/11. The increase was a result of seasonal winter costs and high operating cost properties acquired in the fourth quarter of 2011. Canadian Natural expects operating costs to decline once acquired properties have been fully integrated with existing operations. 2012 full year operating cost guidance for North America natural gas remains at $1.10/Mcf to $1.20/Mcf.
– North Sea crude oil production averaged 23,046 bbl/d during Q1/12 representing a decrease of 32% compared to Q1/11 and a decrease of 14% compared to Q4/11. The decrease from Q1/11 was a result of suspended operations at Banff/Kyle due to damage suffered to the floating production storage offloading vessel (“FPSO”) from severe storm conditions.
– In Q4/11, the Banff/Kyle FPSO was removed from the field after suffering damage from severe storm conditions. The Company is assessing the extent of the damage including associated costs. The incident is an insurable event for both property damage and business interruption insurance.
– Production in Offshore Africa averaged 20,712 bbl/d during Q1/12 representing a decrease of 19% compared to Q1/11 and a decrease of 9% compared to Q4/11. The decrease from Q1/11 was a result of natural field declines. Infill drilling at the Espoir Field is targeted to begin in late 2012, targeting additional production of 6,500 BOE/d at the completion of this drilling program.
– Subsequent to the quarter, Canadian Natural acquired a 36% interest in Block 514 in Cote d–Ivoire. This block–s areal extent is approximately 1,250 square km and has an initial 3 year term in which 3D seismic data will be acquired and a well will be drilled. The Company believes this block is prospective for deepwater channel/fan plays similar to recent discoveries in Ghana and elsewhere in offshore Africa.
– North Sea and Offshore Africa realized crude oil prices increased in Q1/12 by 7% and 26% respectively from Q4/11 partially as a result of the increase in the Brent benchmark pricing.
– SCO production at Horizon averaged 46,090 bbl/d in Q1/12. The decrease from Q4/11 was due to the temporary suspension of production. On February 5, 2012 production at Horizon was suspended for unplanned maintenance on the fractionating unit. Production for the quarter exceeded previously issued guidance as a result of resuming production on March 13, 2012, earlier than originally anticipated. Production in April 2012 averaged approximately 111,500 bbl/d.
– The third OPP and associated hydro-transport unit were successfully integrated into operations in the quarter. The third OPP is expected to increase production reliability going forward by allowing the Company to maintain steady feedstock to the upgrader with two of the three OPPs continually on stream.
– Canadian Natural–s staged expansion to 250,000 bbl/d of SCO production capacity continues to progress on track. Thus far, the Company–s strategy to break the expansion down into smaller more focused projects has proven to be effective. The project capital budget for Horizon for 2012 is $1.88 billion and projects currently under construction are trending at or below cost estimates.
– In Q1/12, WTI pricing increased by 9% from Q1/11 and Q4/11 partially due to supply and demand imbalances.
– The WCS heavy crude oil differential as a percent of WTI averaged 21% in Q1/12. The WCS heavy differential widened in Q1/12 from Q4/11 as a result of planned and unplanned maintenance at key refineries in the United States and Canada. The WCS heavy crude oil differential as a percent of WTI widened to 29% in March and 32% in April. As expected, the differential for May narrowed to 19% and indications in June are for further tightening to approximately 14% as refineries come back on stream.
– During Q1/12, Canadian Natural contributed 152,000 bbl/d of its heavy crude oil stream to the WCS blend. The Company is the largest contributor of the WCS blend, accounting for 51%.
– AECO benchmark natural gas prices decreased 33% compared to Q1/11 and 27% compared to Q4/11, due to supply and demand imbalances in North America.
REDWATER UPGRADING AND REFINING
Supporting and participating in projects that add incremental conversion capacity is a key part of the Company–s marketing strategy. Canadian Natural, in a partnership agreement with North West Upgrading Inc., continues to move forward with detailed engineering regarding the construction and operation of a bitumen refinery near Redwater, Alberta. Project development is dependent upon completion of detailed engineering and final project sanction by the partnership and its partners and approval of the final tolls. Board sanction is currently targeted in 2012.
FINANCIAL REVIEW
The financial position of Canadian Natural remains strong as the Company continues to implement proven strategies and focus on disciplined capital allocation. Canadian Natural–s cash flow generation, credit facilities, its diverse asset base and related capital expenditure programs, and commodity hedging policy all support a flexible financial position and provide the right financial resources for the short, mid and long term. Supporting this are:
– A large and diverse asset base spread over various commodity types; average production amounted to 612,279 BOE/d in Q1/12 with over 96% of production located in G8 countries.
– A strong balance sheet with debt to book capitalization of 26% and debt to EBITDA of 1.0. At March 31, 2012 long-term debt amounted to $8.2 billion compared with $8.5 billion at March 31, 2011.
– Canadian Natural maintains significant financial stability and liquidity represented by approximately $4.1 billion in available unused bank lines at the end of the quarter.
– Canadian Natural–s commodity hedging program protects investment returns, ensures ongoing balance sheet strength and supports the Company–s cash flow for its capital expenditures programs. The Company has hedged approximately 50% of the remaining three quarters of forecasted 2012 crude oil volumes through a combination of puts and collars.
– Subsequent to Q1/12, Toronto Stock Exchange accepted notice of Canadian Natural–s renewal of its Normal Course Issuer Bid through the facilities of Toronto Stock Exchange and the New York Stock Exchange. The notice provides that Canadian Natural may, during the 12 month period commencing April 9, 2012 and ending April 8, 2013, purchase for cancellation on Toronto Stock Exchange and the New York Stock Exchange up to 55,027,447 shares.
– Canadian Natural purchased 692,200 common shares in the quarter for cancellation at a weighted average price of $33.11 per common share. Subsequent to the quarter, the Company purchased a further 521,100 common shares at a weighted average price of $32.21 per common share.
– Declared a quarterly cash dividend on common shares of $0.105 per common share payable July 1, 2012.
OUTLOOK
The Company forecasts 2012 production levels before royalties to average between 1,220 and 1,260 MMcf/d of natural gas and between 440,000 and 480,000 bbl/d of crude oil and NGLs. Q2/12 production guidance before royalties is forecast to average between 1,250 and 1,270 MMcf/d of natural gas and between 453,000 and 482,000 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 operations and future expansion, Primrose, Pelican Lake, the Kirby Thermal Oil Sands Project, the Keystone XL Pipeline US Gulf Coast expansion, and the construction and future operations of the North West Redwater bitumen upgrader and 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 and proved plus probable 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 disruptions or delays in the resumption of the mining, extracting or upgrading of 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, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or Management–s estimates or opinions change.
Management–s Discussion and Analysis
This MD&A 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 three months ended March 31, 2012 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2011.
All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company–s consolidated financial statements for the period ended March 31, 2012 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 December 31, 2011. 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.
A Barrel of Oil Equivalent (“BOE”) is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if 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 a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of this MD&A, crude oil is defined to include the following commodities: light & medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and synthetic crude oil.
Production volumes and per unit 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 three months ended March 31, 2012 in relation to the first quarter of 2011 and the fourth quarter of 2011. The accompanying tables form an integral part of this MD&A. This MD&A is dated May 3, 2012. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2011, is available on SEDAR at , and on EDGAR at .
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
Net earnings for the first quarter of 2012 were $427 million compared to $46 million for the first quarter of 2011 and $832 million for the fourth quarter of 2011. Net earnings for the first quarter of 2012 included net after-tax income of $127 million, compared to net after-tax expenses of $182 million for the first quarter of 2011, and net after-tax expenses of $140 million for the fourth quarter of 2011 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. Excluding these items, adjusted net earnings from operations for the first quarter of 2012 were $300 million, compared to $228 million for the first quarter of 2011 and $972 million for the fourth quarter of 2011.
The increase in adjusted net earnings for the first quarter of 2012 from the first quarter of 2011 was primarily due to:
– higher sales volumes in North America and Horizon segments;
– the impact of a weaker Canadian dollar; and
– higher crude oil and NGLs netbacks;
partially offset by:
– lower natural gas netbacks;
– higher depletion, depreciation and amortization expense; and
– higher realized risk management losses.
The decrease in adjusted net earnings for the first quarter of 2012 from the fourth quarter of 2011 was primarily due to:
– lower synthetic crude oil sales volumes, primarily due to unplanned maintenance on the fractionating unit in the Horizon primary upgrading facility;
– lower crude oil and NGLs and natural gas netbacks;
– higher administration expense;
– higher interest and other financing costs;
– higher realized risk management losses; and
– the impact of a stronger Canadian dollar;
partially offset by:
– higher North America crude oil and NGLs sales volumes; and
– lower depletion, depreciation and amortization expense.
The impacts of share-based compensation, 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 first quarter of 2012 was $1,280 million compared to $1,074 million for the first quarter of 2011 and $2,158 million for the fourth quarter of 2011. The increase in cash flow from operations from the first quarter of 2011 was primarily due to the factors noted above relating to the increase in adjusted net earnings, excluding depletion, depreciation and amortization expense, partially offset by higher cash taxes.
The decrease in cash flow from operations from the fourth quarter of 2011 was primarily due to the factors noted above relating to the decrease in adjusted net earnings, excluding depletion, depreciation and amortization expense, partially offset by lower cash taxes.
Total production before royalties for the first quarter of 2012 increased by 8% to 612,279 BOE/d from 566,231 BOE/d for the first quarter of 2011 and decreased by 7% from 657,599 BOE/d for the fourth quarter of 2011. Production for the first quarter of 2012 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:
– Crude oil pricing – The impact of fluctuating demand, inventory storage levels and geopolitical uncertainties on worldwide benchmark pricing, the impact of the WCS Heavy Differential (“WCS Differential”) from WTI in North America and the impact of the differential between WTI and Dated Brent benchmark pricing in the North Sea and Offshore Africa.
– Natural gas pricing – The impact of fluctuations in both the demand for natural gas and inventory storage levels, and the impact of increased shale gas production in the US, as well as fluctuations in imports of liquefied natural gas into the US.
– Crude oil and NGLs sales volumes – Fluctuations in production due to the cyclic nature of the Company–s Primrose thermal projects, the results from the Pelican Lake water and polymer flood projects, and the impact of the suspension and recommencement of production at Horizon. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the North Sea and Offshore Africa, and payout of the Baobab field in May 2011.
– Natural gas sales volumes – Fluctuations in production due to the Company–s strategic decision to reduce natural gas drilling activity in North America and the allocation of capital to higher return crude oil projects, as well as natural decline rates and the impact and timing of acquisitions.
– Production expense – Fluctuations primarily due to the impact of the demand for services, fluctuations in product mix, the impact of seasonal costs that are dependent on weather, production and cost optimizations in North America, acquisitions of natural gas producing properties that have higher operating costs per Mcf than the Company–s existing properties, and the suspension and recommencement of production at Horizon.
– Depletion, depreciation and amortization – Fluctuations due to changes in sales volumes, proved reserves, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company–s proved undeveloped reserves, the impact of the suspension and recommencement of production at Horizon and the impact of impairments at the Olowi field in Offshore Gabon.
– Share-based compensation – Fluctuations due to the determination of fair market value based on the Black-Scholes valuation model of the Company–s share-based compensation liability.
– Risk management – Fluctuations due to the recognition of gains and losses from the mark-to-market and subsequent settlement of the Company–s risk management activities.
– Foreign exchange rates – Changes in the Canadian dollar relative to the US dollar that impacted the realized price the Company received for its crude oil and natural gas sales, as sales prices are based predominately on US dollar denominated benchmarks. Fluctuations in realized and unrealized foreign exchange gains and losses are recorded with respect to US dollar denominated debt, partially offset by the impact of cross currency swap hedges.
– Income tax expense – Fluctuations in income tax expense include statutory tax rate and other legislative changes substantively enacted in the various periods.
Commodity Prices
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$102.94 per bbl for the first quarter of 2012, an increase of 9% from US$94.25 per bbl for the first quarter of 2011, and an increase of 9% from US$94.02 per bbl for the fourth quarter of 2011. WTI pricing was reflective of the political instability in the Middle East, the optimism in the United States economy, and the expected commencement of the Seaway pipeline reversal from Cushing to the Gulf Coast, offset by lower than expected growth in Asian demand.
Crude oil sales contracts for the Company–s North Sea and Offshore Africa segments are typically based on Dated Brent (“Brent”) pricing, which is representative of international markets and overall world supply and demand. Brent averaged US$118.47 per bbl for first quarter of 2012, an increase of 13% compared to US$105.01 per bbl for the first quarter of 2011 and an increase of 8% from US$109.29 per bbl for the fourth quarter of 2011. The higher Brent pricing relative to WTI was primarily due to the limited pipeline capacity between Petroleum Administration for Defence Districts II (“PADD II”) and the United States Gulf Coast. This logistical constraint is preventing WTI priced barrels delivered into PADD II from obtaining United States Gulf Coast Brent-based pricing.
The WCS Heavy Differential averaged 21% for the first quarter of 2012, compared to 24% in the first quarter of 2011, and 11% for the fourth quarter of 2011. The WCS Heavy Differential widened in the first quarter of 2012, compared to the fourth quarter of 2011, as a result of planned and unplanned maintenance at key PADD II refineries.
The Company uses condensate as a blending diluent for heavy crude oil pipeline shipments. The condensate premium dropped to a more typical 7% premium in the first quarter of 2012 from 16% in the fourth quarter of 2011 as condensate supply and demand were more balanced.
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, changes in transportation logistics and refinery margins.
NYMEX natural gas prices averaged US$2.77 per MMBtu for the first quarter of 2012, a decrease of 33% from US$4.13 per MMBtu for the first quarter of 2011, and a decrease of 23% from US$3.61 per MMBtu for the fourth quarter of 2011. AECO natural gas prices for the first quarter of 2012 averaged $2.39 per GJ, a decrease of 33% from $3.57 per GJ for the first quarter of 2011, and a decrease of 27% from $3.29 per GJ for the fourth quarter of 2011.
Overall natural gas prices continue to be weak in response to the strong North America supply position, primarily from the highly productive shale areas. Additionally, weather related natural gas demand was lower in the first quarter of 2012 as a result of warmer than normal winter temperatures.
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 first quarter of 2012 increased 11% to 395,461 bbl/d from 356,988 bbl/d for the first quarter of 2011 and decreased 11% from 444,286 bbl/d for the fourth quarter of 2011. The increase in production for the first quarter of 2012 from the first quarter of 2011 was primarily related to increased production at Horizon, the impact of a strong heavy crude oil drilling program, and the cyclic nature of the Company–s thermal operations. The decrease from the fourth quarter of 2011 was primarily related to the temporary suspension of production at Horizon during the first quarter of 2012. Crude oil and NGLs production in the first quarter of 2012 was within the Company–s previously issued guidance of 367,000 to 400,000 bbl/d.
Natural gas production for the first quarter of 2012 increased by 4% to 1,302 MMcf/d from 1,256 MMcf/d from the first quarter of 2011 and increased by 2% from 1,280 MMcf/d from the fourth quarter of 2011. The increase in natural gas production from the comparable periods in 2011 reflects the new production volumes from natural gas producing properties acquired during 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. The Company shut in approximately 16 MMcf/d of natural gas production in the first quarter of 2012 due to low natural gas prices. Natural gas production in the first quarter of 2012 was within the Company–s previously issued guidance of 1,300 to 1,320 MMcf/d.
For 2012, annual production guidance is targeted to average between 440,000 and 480,000 bbl/d of crude oil and NGLs and between 1,220 and 1,260 MMcf/d of natural gas. Second quarter 2012 production guidance is targeted to average between 453,000 and 482,000 bbl/d of crude oil and NGLs and between 1,250 and 1,270 MMcf/d of natural gas.
North America – Exploration and Production
For the first quarter of 2012, crude oil and NGLs production increased 5% to average 305,613 bbl/d, compared to 290,130 bbl/d for the first quarter of 2011 and 291,839 bbl/d for the fourth quarter of 2011. Increases in crude oil and NGLs production from comparable periods were primarily due to the impact of a strong heavy crude oil drilling program and the cyclic nature of the Company–s thermal operations. Production of crude oil and NGLs was within the Company–s previously issued guidance of 297,000 bbl/d to 309,000 bbl/d for the first quarter of 2012. Second quarter 2012 production guidance is targeted to average between 312,000 and 325,000 bbl/d of crude oil and NGLs.
Natural gas production increased 5% to 1,281 MMcf/d for the first quarter of 2012 compared to 1,225 MMcf/d in the first quarter of 2011 and increased 2% compared to 1,255 MMcf/d in the fourth quarter of 2011. Natural gas production for the first quarter of 2012 and the fourth quarter of 2011 reflected new production volumes from natural gas producing properties acquired during 2011, offset by the impact of 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. During the first quarter of 2012, the Company reduced its drilling activities and shut in approximately 16 MMcf/d of gas volumes due to natural gas price declines.
North America – Oil Sands Mining and Upgrading
For the first quarter of 2012, crude oil and NGLs production averaged 46,090 bbl/d, compared to 7,269 bbl/d for the first quarter of 2011 and 102,952 bbl/d for the fourth quarter of 2011.
The Company temporarily suspended synthetic crude oil production at Horizon on February 5, 2012 to complete unplanned maintenance on the fractionating unit in the primary upgrading facility. On March 13, 2012 the Company successfully and safely completed the unplanned maintenance on the fractionating unit. Second quarter 2012 production guidance is targeted to average between 105,000 and 115,000 bbl/d of SCO.
North Sea
First quarter 2012 North Sea crude oil production decreased 32% to 23,046 bbl/d from 34,101 bbl/d for the first quarter of 2011, and decreased 14% from 26,769 bbl/d for the fourth quarter of 2011. The decrease in production volumes from the comparable periods in 2011 was primarily due to natural field declines and the suspension of production at Banff/Kyle. In December 2011, the Banff Floating Production, Storage and Offloading Vessel (“FPSO”) and subsea infrastructure suffered storm damage. Operations at Banff/Kyle, with combined net production of approximately 3,500 bbl/d, were suspended and appropriate shut down procedures were activated. The FPSO and associated floating storage unit have subsequently been removed from the field, and the extent of the damage, including associated costs and timing of returning to the field, is currently being assessed.
Offshore Africa
First quarter crude oil production averaged 20,712 bbl/d, decreasing 19% from 25,488 bbl/d for the first quarter of 2011 and 9% from 22,726 in the fourth quarter of 2011. The decrease in production volumes from the comparable periods in 2011 was due to natural field declines and the payout of the Baobab field in May 2011.
International Guidance
The Company–s North Sea and Offshore Africa first quarter 2012 crude oil and NGLs production was within the Company–s previously issued guidance of 40,000 to 46,000 bbl/d. Second quarter 2012 production guidance is targeted to average between 36,000 and 42,000 bbl/d of crude oil.
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 averaged $74.27 per bbl for the first quarter of 2012, an increase of 19% compared to $62.21 per bbl for the first quarter of 2011 and a decrease of 8% compared to $81.02 per bbl for the fourth quarter of 2011. The increase in prices for the first quarter of 2012 compared to the first quarter of 2011 was primarily a result of higher benchmark WTI pricing, the narrowing WCS Heavy Differential and the impact of a weaker Canadian dollar relative to the US dollar. The decrease in prices relative to the fourth quarter of 2011 was due to a widening WCS Heavy Differential and the impact of a stronger Canadian dollar relative to the US dollar; partially offset by higher benchmark WTI pricing. The Company continues to focus on its crude oil blending marketing strategy, and in the first quarter of 2012 contributed approximately 152,000 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 upgrader refinery near Redwater, Alberta. In addition, the partnership has entered into a 30 year fee-for-service agreement to process bitumen supplied by the Company and the Government of Alberta under the Bitumen Royalty In Kind initiative. Project development is dependent upon completion of detailed engineering and final project sanction by the partnership and its partners and approval of the final tolls. Board sanction is currently targeted in 2012.
North America realized natural gas prices decreased 37% to average $2.36 per Mcf for the first quarter of 2012, compared to $3.77 per Mcf in the first quarter of 2011, and decreased 30% compared to $3.36 per Mcf for the fourth quarter of 2011. The decrease in natural gas prices from the comparable periods in 2011 was primarily due to lower NYMEX and AECO benchmark pricing related to the impact of strong supply from US shale projects and the effects of a warmer than normal winter.
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 averaged $117.03 per bbl for the first quarter of 2012, an increase of 14% from $102.51 per bbl for the first quarter of 2011, and 7% from $109.71 for the fourth quarter of 2011. The increase in realized crude oil prices in the North Sea for the first quarter of 2012 from the comparable periods in 2011 was primarily the result of higher Brent benchmark pricing and fluctuations in the Canadian dollar.
Offshore Africa
Offshore Africa realized crude oil prices increased 33% to average $128.94 per bbl for the first quarter of 2012 from $97.09 per bbl for the first quarter of 2011, and an increase of 26% from $102.74 per bbl for the fourth quarter of 2011. The increase in realized crude oil prices in Offshore Africa for the first quarter of 2012 from the comparable periods in 2011 was primarily the result of higher Brent benchmark pricing and the timing of liftings, together with the impact of fluctuations in the Canadian dollar.
North America
North America crude oil and natural gas royalties for the three months ended March 31, 2012 compared to the comparable periods in 2011 reflected benchmark commodity prices.
Crude oil and NGLs royalties averaged approximately 19% of product sales for the first quarter of 2012 and the first quarter of 2011 compared to 21% for the fourth quarter of 2011. Crude oil and NGLs royalties per bbl are anticipated to average 18% to 21% of product sales for 2012.
Natural gas royalties averaged approximately 1% of product sales for the first quarter of 2012, compared to 3% for the first quarter of 2011 and 4% for the fourth quarter of 2011. Natural gas royalties are anticipated to average 1% to 3% of product sales for 2012.
Offshore Africa
Under the terms of the various Production Sharing Contracts, royalty rates fluctuate based on realized commodity pricing, capital costs, the status of payouts and the timing of liftings from each field.
Royalty rates as a percentage of product sales averaged approximately 16% for the first quarter of 2012 compared to 9% for the first quarter of 2011 and 18% for the fourth quarter of 2011. The increase in royalty rates from the first quarter of 2011 was due to payout of the Baobab field in May 2011 and higher crude oil prices during the year.
Offshore Africa royalty rates are anticipated to average 13% to 15% of product sales for 2012.
North America
North America crude oil and NGLs production expense for the first quarter of 2012 increased 25% to $15.40 per bbl from $12.28 per bbl for the first quarter of 2011 and increased 8% from $14.32 per bbl for the fourth quarter of 2011. The increase in production expense per barrel from the comparable periods in 2011 was a result of higher overall service costs relating to heavy crude oil production and seasonality. North America crude oil and NGLs production expense is anticipated to average $11.00 to $13.00 per bbl for 2012.
North America natural gas production expense for the first quarter of 2012 increased 15% to $1.33 per Mcf from $1.16 per Mcf for the first quarter of 2011, and increased 19% from $1.12 per Mcf for the fourth quarter of 2011. Natural gas production expense increased from the comparable periods in 2011 due to the impact of normal seasonal costs associated with winter access and colder weather and acquisitions of natural gas producing properties that have higher operating costs per Mcf than the Company–s existing properties. These acquisitions closed late in the fourth quarter of 2011 and costs are expected to decline once the acquisitions are fully integrated into the Company–s operations. North America natural gas production expense is anticipated to average $1.10 to $1.20 per Mcf for 2012.
North Sea
North Sea crude oil production expense for the first quarter of 2012 increased 20% to $36.53 per bbl from $30.46 per bbl for the first quarter of 2011, and was comparable to $36.45 per bbl in the fourth quarter of 2011. Production expense increased on a per barrel basis from the comparable periods in 2011 due to lower production volumes on relatively fixed costs and increased fuel prices. North Sea crude oil production expense is anticipated to average $43.00 to $48.00 per bbl for 2012.
Offshore Africa
Offshore Africa crude oil production expense for the first quarter of 2012 averaged $12.17 per bbl, a decrease of 36% compared to $19.13 per bbl for the first quarter of 2011 and a decrease of 45% compared to $22.16 per bbl for the fourth quarter of 2011. Production expense decreased from the comparable periods in 2011 due to the timing of liftings from various fields, which have different cost structures. Offshore Africa crude oil production expense is anticipated to average $27.00 to $29.00 per bbl for 2012.
Depletion, depreciation and amortization expense increased for the first quarter of 2012 from the comparable periods in 2011 due to higher production volumes in North America associated with heavy oil drilling and higher overall future development costs, partially offset by lower production volumes in the North Sea and Offshore Africa.
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
The Company temporarily suspended synthetic crude oil production at Horizon on February 5, 2012 to complete unplanned maintenance on the fractionating unit in the primary upgrading facility. On March 13, 2012 the Company successfully and safely completed the unplanned maintenance on the fractionating unit.
Realized SCO sales prices averaged $97.09 per bbl for the first quarter of 2012, an increase of 17% compared to $82.93 per bbl for the first quarter of 2011, and a decrease of 6% compared to $103.16 per bbl in the fourth quarter of 2011, reflecting the relative changes in WTI and Brent benchmark pricing.
PRODUCTION COSTS – OIL SANDS MINING AND UPGRADING
The following tables are reconciled to the Oil Sands Mining and Upgrading production costs disclosed in the Company–s unaudited interim consolidated financial statements.
Adjusted cash production costs for the first quarter of 2012 averaged $46.24 per bbl, comparable to $45.69 per bbl for the first quarter of 2011, and an increase of 28% compared to $36.04 per bbl in the fourth quarter of 2011. The increase in cash production costs per bbl from the fourth quarter of 2011 was primarily due to the impact of the ramp up of production related to the repair of the fractionating unit during the first quarter of 2012.
Depletion, depreciation and amortization expense for the first quarter of 2012 increased compared to the first quarter of 2011 due to higher production volumes. The decrease from the fourth quarter of 2011 was due to lower production volumes resulting from the temporary suspension of production during the first quarter of 2012.
The Company–s stock option plan provides current employees with the right to receive common shares or a direct cash payment in exchange for stock options surrendered.
The Company recorded a $107 million share-based compensation recovery for the three months ended March 31, 2012, primarily as a result of remeasurement of the fair value of outstanding stock options at the end of the period related to a decrease in the Company–s share price, offset by normal course graded vesting of stock options granted in prior periods and the impact of vested stock options exercised or surrendered during the period. For the three months ended March 31, 2012, a $7 million recovery was recognized in respect of capitalized share-based compensation to Oil Sands Mining and Upgrading (December 31, 2011 – $ nil; March 31, 2011 – $11 million capitalized).
For the three months ended March 31, 2012, the Company paid $7 million for stock options surrendered for cash settlement (December 31, 2011 – $ 2 million; March 31, 2011 – $10 million).
Gross interest and other financing costs for the first quarter of 2012 increased compared to the first quarter of 2011 due to higher average US dollar debt levels and the impact of a weaker Canadian dollar related to US dollar interest, partially offset by lower average interest rates on fixed rate debt. Gross interest and other financing costs increased compared to the fourth quarter of 2011 due to higher interest rates and interest income recoveries recognized in the fourth quarter of 2011, partially offset by lower average debt levels and a stronger Canadian dollar. Capitalized interest for the three months ended March 31, 2012 increased from the first quarter of 2011 relating to Horizon and the Kirby Project, and was comparable to the fourth quarter of 2011.
The Company–s average effective interest rate for the first quarter of 2012 was consistent to the comparable periods in 2011.
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 March 31, 2012 are disclosed in note 13 to the Company–s unaudited interim consolidated financial statements.
The Company recorded a net unrealized loss of $60 million ($40 million after-tax) on its risk management activities for the three months ended March 31, 2012 (December 31, 2011 – unrealized loss of $58 million; $50 million after-tax; March 31, 2011 – unrealized loss of $54 million; $39 million after-tax), primarily due to changes in crude oil forward pricing and the reversal of prior period unrealized gains and losses related to crude oil and foreign currency contracts.
The net realized foreign exchange loss for the three months ended March 31, 2012 was primarily due to foreign exchange rate fluctuations on settlement of working capital items denominated in US dollars or UK pounds sterling. The net unrealized foreign exchange gain for the three months ended March 31, 2012 was primarily related 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 (three months ended March 31, 2012- unrealized loss of $42 million; December 31, 2011 – unrealized loss of $43 million; March 31, 2011 – unrealized loss of $48 million). The Canadian dollar ended the first quarter at US$1.0009 (December 31, 2011 – US$0.9833; March 31, 2011 – US$1.0290).
The increase in the effective income tax rate on adjusted net earnings in the first quarter of 2012 from the fourth quarter of 2011 was primarily due to the impact of the temporary suspension of production at Horizon due to unplanned maintenance on the fractionating unit.
During the fourth quarter of 2011, the Canadian Federal government enacted legislation to implement several taxation changes. These changes include a requirement that, beginning in 2012, partnership income must be included in the taxable income of the corporate partners based on the tax year of the partner, rather than the fiscal year of the partnership. The legislation includes a five-year transition provision and has no impact on net earnings.
In its 2012 budget, the UK government confirmed its intention to restrict tax relief on decommissioning expenditures to 50% for non-PRT fields and 75% for PRT fields. The legislation is expected to be substantively enacted in the second or third quarter of 2012. This tax change will result in a deferred tax charge currently estimated at $56 million.
During the first quarter of 2011, the UK government 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%. 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 files income tax returns in the various jurisdictions in which it operates. These tax returns are subject to periodic examinations in the normal course by the applicable tax authorities. The tax returns as prepared may include filing positions that could be subject to differing interpretations of applicable tax laws and regulations, which may take several years to resolve. The Company does not believe the ultimate resolution of these matters will have a material impact upon the Company–s results of operations, financial position or liquidity.
For 2012, based on budgeted prices and the current availability of tax pools, the Company expects to incur current income tax expense of $600 million to $700 million in Canada and $275 million to $375 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 areas. 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 owning associated infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production costs.
Net capital expenditures for the three months ended March 31, 2012 were $1,596 million compared to $1,694 million for the three months ended March 31, 2011 and $1,909 million for the fo