Canadian Natural Resources Limited Announces 2011 Third Quarter Results and 2012 Budget
(firmenpresse) - CALGARY, ALBERTA -- (Marketwire) -- 11/03/11 -- Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ) -
Commenting on third quarter results, Canadian Natural's Chairman, Allan Markin stated, "Our experienced team produced excellent operating and financial results across all operating areas in Q3/11. Production successfully recommenced at Horizon and our North America E&P operations achieved record production at both our primary heavy oil and thermal in situ operations.
The Company delivered on its commitment to safely restore full production at Horizon in Q3/11. Operations recommenced on August 16, 2011 and production ramped up in September to average approximately 108,200 bbl/d of SCO. With turnaround and opportune maintenance complete and a portion of the 2012 turnaround deferred to 2013, we look forward in 2012 to solid production and cash flow generation from Horizon."
John Langille, Vice-Chairman of Canadian Natural continued, "We have significant capital flexibility in the 2012 capital program allowing us to quickly adapt our capital spending profile to changing market conditions. Cash flow generation in 2012 will enable us to execute the capital program, capitalize on value adding opportunistic acquisitions, pre-invest in long term projects, and manage our dividends and debt levels."
Steve Laut, President of Canadian Natural stated, "In 2012 we are targeting 24% crude oil and NGL production growth, 17% overall BOE production growth and 10% production growth Q4/11 to Q4/12, reflective of a strong primary heavy oil drilling program, continued pad development at Primrose, Canadian light oil and NGL growth and solid production from Horizon. The Company will continue to focus on developing its top quality Oil Sands assets as we continue to transform the Company into a longer life, sustainable asset base capable of generating significant economic returns for years well beyond 2012."
- Production in Q3/11 in all areas met or exceeded previously issued guidance as a result of efficient and effective operations. Thermal in situ ("bitumen") and primary heavy crude oil had record quarterly production contributing to strong North America E&P crude oil production. Continued success at Septimus together with production from properties acquired in 2011 resulted in North America natural gas production slightly above previously issued guidance.
- Total crude oil and NGLs production for Q3/11 was 403,900 bbl/d. Q3/11 crude oil production volumes decreased 2% from Q3/10 levels of 411,585 bbl/d and increased by 15% from Q2/11 level of 349,915 bbl/d. The increase from the previous quarter was primarily due to the recommencement of production at Horizon, the impact of a record primary heavy oil drilling program and excellent thermal in situ performance. The decrease from Q3/10 was primarily related to the suspension of production at Horizon for the first half of Q3/11.
- Crude oil and NGLs production from North America E&P operations in Q3/11 was 304,671 bbl/d. Q3/11 crude oil and NGLs production volumes increased 14% from Q3/10 levels of 267,177 bbl/d, and increased 3% from Q2/11 levels of 295,715 bbl/d. The increase in production from Q3/10 and Q2/11 was primarily due to the impact of a record heavy oil drilling program, new pad additions at Primrose and the cyclic nature of the Company's thermal in situ operations.
- Natural gas production from North America operations in Q3/11 was above the Company's previously issued guidance of 1,205 MMcf/d to 1,225 MMcf/d. North America natural gas production decreased 1% to 1,226 MMcf/d for Q3/11 compared to 1,234 MMcf/d in Q3/10 and increased 1% compared to 1,218 MMcf/d in Q2/11. Natural gas production reflects continued strong production volumes from Septimus in NE British Columbia, the impact of natural gas producing properties acquired during 2011 and the impact of the strategic reduction of natural gas drilling activity.
- Quarterly cash flow from operations was $1.77 billion compared to $1.55 billion for Q3/10 and $1.55 billion for Q2/11. The increase in cash flow from Q3/10 was primarily related to higher North America crude oil and NGL sales volumes and higher crude oil and NGL netbacks, partially offset by the impact of lower production at Horizon. The increase in cash flow from Q2/11 was primarily a result of the recommencement of production at Horizon.
- Adjusted net earnings from operations for Q3/11 was $719 million, compared to adjusted net earnings of $573 million in Q3/10 and $621 million in Q2/11. Changes in adjusted net earnings reflect the changes in cash flow from operations.
- Primary heavy crude oil operations achieved record quarterly production for the third consecutive quarter. Production exceeded 101,500 bbl/d in Q3/11 as part of the targeted record drilling program in 2011. As at Q3/11 the Company has drilled 565 net primary heavy crude oil wells which will contribute to a targeted 10% annual production growth in primary heavy crude oil. Primary heavy crude oil continues to provide the highest return on capital projects in the Company's portfolio.
- Thermal in situ crude oil achieved record quarterly production of approximately 110,000 bbl/d in Q3/11 due to continued pad additions at Primrose, excellent overall performance in the quarter and the nature of the steaming and production cycles. Production in 2011 is targeted to average between 97,000 bbl/d and 98,000 bbl/d with the normal peaks and valleys inherent to cyclic steam stimulation.
- Construction at the Kirby South Phase 1 ("Kirby") Steam Assisted Gravity Drainage ("SAGD") project remains on cost and on schedule. Drilling has been completed on the first of seven pads and has commenced on the second pad. Completion of the second pad is targeted for Q4/11. Kirby has targeted capital costs of $1.25 billion and first steam-in is targeted for late 2013. Production is targeted to ramp to 40,000 bbl/d with facility capacity of 45,000 bbl/d providing the ability to optimize performance. The total project is 29% complete at the end of Q3/11.
- Regulatory approvals required to execute the 2012 expansion plans at Pelican Lake were received in the quarter.
- Synthetic crude oil ("SCO") production at the Horizon Oil Sands successfully and safely resumed on August 16, 2011. August average production was approximately 44,800 bbl/d, September averaged approximately 108,200 bbl/d and October averaged approximately 105,600 reflective of the coker furnace pigging completed in October 2011.
- Subsequent to Q3/11, commissioning of the third Ore Preparation Plant ("OPP") and associated hydro-transport began on time and on budget with completion targeted by the end of November 2011 followed by start-up. The third OPP will increase production reliability and result in higher plant uptime in 2012 at Horizon.
- The Company repurchased 3.071 million common shares year-to-date at an average cost of $33.68/share under the Company's Normal Course Issuer Bid.
- Subsequent to Q3/11 Standard and Poor's Financial Services LLC upgraded the Company's unsecured credit rating to BBB+ (Stable outlook) from BBB (Positive outlook).
- Declared a quarterly cash dividend on common shares of $0.09 per common share payable January 1, 2012
HIGHLIGHTS OF THE 2012 BUDGET
- Targeted overall production growth of 17% based on production guidance of 675,000 - 726,000 BOE/d as part of a product mix encompassing approximately 70% crude oil and NGL and 30% natural gas. Total production growth from Q4/11 to Q4/12 is targeted at 10%.
- Crude oil and NGL production is targeted to increase 24% from 2011 levels reflecting the return of production at Horizon, primary heavy oil growth of 16%, thermal in situ growth of 10%, and North America light oil and NGL growth of 17%.
- North America natural gas production is targeted to grow 3% reflecting economic drilling activities at Septimus and certain other liquids rich plays in NE British Columbia and NW Alberta as well as acquisitions completed in 2011.
- Cash flow is targeted at $8.2 billion to $8.6 billion based on average annual WTI strip pricing of US$88.12/bbl and AECO strip pricing of C$3.45/GJ.
- Capital spending in 2012 is budgeted at $7.2 billion, including $3.8 billion of long-term project developments and $3.0 billion of flexible capital spending.
- Free cash flow (cash flow after capital expenditures excluding acquisitions) is targeted between $1.1 billion and $1.5 billion.
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, thermal in situ, SCO and NGLs. A large diversified project portfolio enables the effective allocation of capital to higher return opportunities.
- Natural gas production from North America operations in Q3/11 was above the Company's previously issued guidance of 1,205 MMcf/d to 1,225 MMcf/d. North America natural gas production decreased 1% to 1,226 MMcf/d for Q3/11 compared to 1,234 MMcf/d in Q3/10 and increased 1% compared to 1,218 MMcf/d in Q2/11. Natural gas production reflects continued strong production volumes from Septimus in NE British Columbia, the impact of natural gas producing properties acquired during 2011 and the impact of the strategic reduction of natural gas drilling activity.
- In Q3/11 the Company continued to focus on the development of its liquids rich unconventional natural gas plays in NE British Columbia and NW Alberta. These selected properties compete for capital against the company's robust oil projects.
- Planned drilling activity for Q4/11 includes 23 net natural gas wells, substantially targeting liquids rich plays.
- Crude oil and NGLs production from North America E&P operations in Q3/11 was 304,671 bbl/d. Q3/11 crude oil and NGLs production volumes increased 14% from Q3/10 levels of 267,177 bbl/d, and increased 3% from Q2/11 levels of 295,715 bbl/d. The increase in production from Q3/10 and Q2/11 was primarily due to the impact of a record heavy oil drilling program, new pad additions at Primrose and the cyclic nature of the Company's thermal in situ operations.
- Primary heavy crude oil operations achieved record quarterly production for the third consecutive quarter. Production exceeded 101,500 bbl/d in Q3/11 as part of the targeted record drilling program in 2011. The Company has drilled 565 net primary heavy crude oil wells in 2011 which will contribute to a targeted 10% annual production growth in primary heavy crude oil. Primary heavy crude oil continues to provide the highest return on capital projects in the Company's portfolio.
- Regulatory approvals required to execute the 2012 expansion plans at Pelican Lake were received in the quarter. Development of Pelican Lake is continuing and polymer response is positive. Continued work to optimize capital efficiencies and monitor ongoing polymer response will result in the next phase of commercial development being delayed. This will facilitate the ability to capture opportunities to optimize well configuration and injection strategies.
- The Company's focus on its high quality thermal in situ crude oil assets resulted in record quarterly production in Q3/11 of approximately 110,000 bbl/d. Development of new low cost pads at Primrose continue on track and on budget. Construction at the Kirby SAGD project remains on cost and on schedule. Drilling has been completed on the first of seven pads and has commenced on the second pad. Completion of the second pad is targeted for Q4/11. Kirby has targeted capital costs of $1.25 billion and first steam-in is targeted for late 2013. Production is targeted to ramp to 40,000 bbl/d with facility capacity of 45,000 bbl/d providing the ability to optimize performance. The total project is 29% complete at the end of Q3/11.
- During Q3/11, 327 net crude oil wells were drilled.
- Planned drilling activity for Q4/11 includes 47 net thermal in situ wells and 321 net crude oil wells, excluding stratigraphic test and service wells.
- North Sea crude oil production was 26,350 bbl/d during Q3/11. Crude oil production decreased 3% in Q3/11 from Q3/10 and 20% from Q2/11 due to scheduled turnarounds at the Ninian South and Tiffany platforms and natural field declines. The maintenance shutdowns were completed on time and on budget and the fields have returned to normal production.
- 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, the Company's development activities in the North Sea have been reduced. The Company will continue to high grade all North Sea prospects for potential future development opportunities.
- Production in Offshore Africa was 22,525 bbl/d in Q3/11 slightly exceeding the Company's previously issued guidance of 19,000 bbl/d to 22,000 bbl/d primarily as a result of the early reinstatement of production at Olowi.
- SCO production at the Horizon Oil Sands successfully and safely resumed on August 16, 2011. August average production was approximately 44,800 bbl/d, September averaged approximately 108,200 bbl/d and October averaged approximately 105,600 bbl/d reflective of the coker furnace pigging completed in October.
- Turnaround and opportune maintenance have been completed. Portions of the turnaround originally scheduled for 2012 have been accelerated and remaining portions of that turnaround are now expected to be deferred to 2013.
- Subsequent to Q3/11 commissioning of the third OPP and associated hydro-transport began on time and on budget with completion targeted by the end of November 2011 followed by start-up. The third OPP will increase production reliability and result in higher plant uptime in 2012 at Horizon..
- Horizon expansion activities continue to progress on track and are at or below cost estimates.
- In Q3/11, WTI pricing decreased by 12% from Q2/11 primarily due to continued high inventory levels of crude oil at Cushing, the relative strength of the US dollar and the impact of increased supply of North American light crude oil.
- The Western Canadian Select ("WCS") heavy crude oil differential as a percent of WTI averaged 20% in Q3/11 compared with 20% in Q3/10 and 17% in Q2/11. The WCS heavy differential widened in Q3/11 from the prior quarter partially due to the impact of pipeline transportation restrictions and unplanned outages at refining facilities.
- During Q3/11, the Company contributed approximately 139,000 bbl/d of its heavy crude oil streams to the WCS blend. Canadian Natural is the largest contributor accounting for 55% of the WCS blend.
REDWATER UPGRADING AND REFINING
- 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 had entered into a 30 year fee-for-service agreement to process bitumen supplied by 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 approval of the final resulting tolls. Board sanction is currently targeted for 2012.
FINANCIAL REVIEW
- The financial position of Canadian Natural remains strong as the Company continues to focus on capital allocation and the execution of implemented strategies. Canadian Natural's 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 578,618 BOE/d in the first nine months of 2011 and 95% of production was located in G8 countries.
-- With cash flow from operations of approximately $4.4 billion in the nine months of 2011 and available unused bank lines of approximately $2.2 billion at September 30, 2011, the Company maintains significant financial stability and liquidity.
-- During the third quarter of 2011, $400 million of US dollar denominated debt securities bearing interest of 6.7% were repaid.
-- Subsequent to Q3/11 Standard and Poor's Financial Services LLC upgraded the Company's unsecured credit rating to BBB+ (Stable outlook) from BBB (Positive outlook).
-- The Company repurchased 3.071 million common shares year-to-date at an average cost of $33.68/share under the Company's Normal Course Issuer Bid.
-- Declared a quarterly cash dividend on common shares of $0.09 per common share payable January 1, 2012.
-- A strong balance sheet with debt to book capitalization of 30% and debt to EBITDA of 1.2 times; Canadian Natural's long term debt at September 30, 2011 amounted to $9.3 billion compared with $8.5 billion at
September 30, 2010.
OUTLOOK
The Company forecasts 2011 production levels before royalties to average between 1,256 and 1,263 MMcf/d of natural gas and between 385,000 and 393,000 bbl/d of crude oil and NGLs. Q4/11 production guidance before royalties is forecast to average between 1,279 and 1,304 MMcf/d of natural gas and between 430,000 and 461,000 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 .
DETAILS OF THE 2012 BUDGET
- Equivalent production target of 675,000 to 726,000 BOE/d before royalties, representing a midpoint increase of 17% from the midpoint of 2011 average production guidance. Q4/11 to Q4/12 production is targeted to increase 10% in 2012.
- Crude oil and NGLs production target of 464,000 to 504,000 bbl/d before royalties, representing a midpoint increase of 24% from the midpoint of 2011 guidance. Q4/11 to Q4/12 production is targeted to increase 16%.
-- Primary heavy crude oil is targeted to increase 16% from 2011 to between 114,000 bbl/d and 122,000 bbl/d as a result of the continued strong drilling program and development of our large unproved land base.
-- Thermal in situ is targeted to grow 10% in 2012 to between 104,000 bbl/d and 110,000 bbl/d as a result of continued low cost pad developments at Primrose;
-- Significant increase in North America Light oil and NGL production as a result of enhanced oil recovery ("EOR") projects, a large drilling program consisting of 134 net wells (including 80 net horizontal wells) and the plant expansion at Septimus. Production is targeted to increase 17% in 2012.
-- Increased production reliability at Horizon Oil Sands targeting mid-point guidance of 110,000 bbl/d through 2012. Guidance for 2012 is set at 105,000 bbl/d to 115,000 bbl/d.
- Natural gas production target of 1,265 to 1,334 MMcf/d before royalties, representing a midpoint increase of 3% from the midpoint of 2011 forecasted annual guidance. The increase reflects production from natural gas producing properties acquired in 2011 and continued development of liquids rich natural gas properties.
- Capital spending in 2012 is budgeted at $7.2 billion, an 18% increase over 2011. The Company's balanced asset base and high working interest and operatorship allows for significant flexibility and efficiency in the capital allocation decision making process. Capital flexibility in the 2012 budget is targeted at $3.0 billion.
- The 2012 capital budget reflects:
-- Continuation of significant primary heavy crude oil drilling in 2012 targeting 808 net wells (including over 100 net horizontal wells) which provide significant return on capital.
-- In 2012 the focus at Pelican Lake will be on injection optimization and monitoring polymer response. Pelican Lake capital spending in 2012 includes upgrades to existing batteries, which is necessary to handle additional production. As well, construction of a new battery at Pelican Lake will commence in 2012 with initial start-up capacity designed for 25,000 bbl/d with targeted completion in mid 2013. The new battery will handle the additional polymer driven targeted production from Pelican Lake.
-- Development will continue at Primrose in 2012. The Company is targeting to bring on five additional pads at Primrose East and three additional pads at Primrose South contributing 20,000 bbl/d and 15,000 bbl/d respectively of additional capacity at a cost of approximately $13,000 per flowing barrel of capacity.
-- Budgeted capital for Kirby South Phase 1 is targeted at $710 million to support the completion of engineering, receipt of all major equipment, ramp up of construction, and the completion of three additional pads.
-- Budgeted capital expenditures at Horizon for 2012 reflect the Board of Directors approval of approximately $2 billion in targeted strategic expansion. The Company is committed to a disciplined execution strategy and therefore expansion plans will only proceed as cost certainty is achieved.
-- North America Light Oil and NGL includes capital allocated to new EOR projects and nine new pool developments.
-- International Light Oil activities in 2012 will include a production well at the Tiffany platform in the North Sea as well as workovers at the Ninian platform and a subsea pump installation at the Lyell Field. In Offshore Africa preparations for the Espoir infill drilling program will commence.
-- Natural gas spending in 2012 will continue to focus on lease preservation and the Company's liquid rich shale gas plays. In 2012 the plant at Septimus will be expanded to 120 MMcf/d, yielding 10,800 bbl/d of liquids following processing through the plant and deep cut facilities. Targeted net horizontal wells at Septimus are approximately 17 with an additional 30 horizontal wells targeting liquids rich natural gas with horizontal multi frac technology.
- Cash Flow is targeted at $8.2 billion to $8.6 billion based on average annual WTI strip pricing of US$88.12/bbl and AECO strip pricing of C$3.45/GJ.
- Free cash flow (cash flow after capital excluding acquisitions), is targeted between $1.1 billion and $1.5 billion. Free cash flow will initially be used for opportunistic acquisitions, increased dividends, and debt reduction.
- Continued strong balance sheet management which provides financial flexibility for operating plans.
Production and Capital Guidance
Canadian Natural continues its strategy of maintaining a large portfolio of varied projects. This enables the Company to provide consistent growth in production and high shareholder returns over an extended period of time. Annual budgets are developed, scrutinized throughout the year and changed if necessary in the context of project returns, product pricing expectations, and balance project risks and time horizons. Canadian Natural maintains a high ownership level and operatorship in its properties and can therefore control the nature, timing and extent of expenditures in each of its project areas.
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 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 future operations 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 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 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 nine months ended September 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 September 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 November 1, 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 nine and three months ended September 30, 2011 in relation to the comparable periods in 2010 and the second quarter of 2011. The accompanying tables form an integral part of this MD&A. This MD&A is dated November 1, 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 nine months ended September 30, 2011 were $1,811 million compared to $1,982 million for the nine months ended September 30, 2010. Net earnings for the nine months ended September 30, 2011 included net after-tax income of $243 million related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, the impact of realized foreign exchange gain on repayment of long-term debt and the impact of statutory tax rate and other legislative changes on deferred income tax liabilities, compared to net after-tax income of $123 million for the nine months ended September 30, 2010. Excluding these items, adjusted net earnings from operations for the nine months ended September 30, 2011 were $1,568 million, compared to $1,859 million for the nine months ended September 30, 2010.
Net earnings for the third quarter of 2011 were $836 million compared to $596 million for the third quarter of 2010 and $929 million for the prior quarter. Net earnings for the third quarter of 2011 included net after-tax income of $117 million related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates and the impact of realized foreign exchange gain on repayment of long-term debt, compared to net after-tax income of $23 million for the third quarter of 2010 and $308 million for the prior quarter. Excluding these items, adjusted net earnings from operations for the third quarter of 2011 were $719 million compared to $573 million for the third quarter of 2010 and $621 million for the prior quarter.
The decrease in adjusted net earnings for the nine months ended September 30, 2011 from the comparable period in 2010 was primarily due to lower synthetic crude oil ("SCO") sales revenue, together with continuing production expenses associated with the suspension of production at Horizon ("Horizon suspension") partially offset by business interruption insurance ("insurance"). On January 6, 2011, a fire occurred at the Company's primary upgrading coking plant. Horizon successfully and safely recommenced operations on August 16, 2011.
Other factors contributing to the decrease in adjusted net earnings were:
- lower natural gas netbacks;
- realized risk management losses; and
- the impact of a stronger Canadian dollar;
partially offset by:
- higher North America crude oil and NGL sales volumes; and
- higher crude oil and NGL netbacks.
The increase in adjusted net earnings from the third quarter of 2010 was due to:
- higher North America crude oil and NGL sales volumes; and
- higher crude oil and NGL netbacks;
partially offset by:
- the impact of the Horizon suspension net of insurance;
- lower natural gas netbacks;
- higher administration expense;
- lower realized risk management gains; and
- the impact of a stronger Canadian dollar.
The increase in adjusted net earnings from the prior quarter was due to:
- the recommencement of production at Horizon and insurance;
- realized risk management gains; and
- the impact of a weaker Canadian dollar;
partially offset by lower crude oil and NGL netbacks.
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 nine months ended September 30, 2011 was $4,389 million compared to $4,681 million for the nine months ended September 30, 2010. Cash flow from operations for the third quarter of 2011 was $1,767 million compared to $1,545 million for the third quarter of 2010 and $1,548 million for the prior quarter. The decrease in cash flow from operations for the nine months ended September 30, 2011 from the comparable period in 2010 was primarily due to the Horizon suspension net of insurance. Other factors contributing to the decrease were:
- lower natural gas netbacks;
- realized risk management losses; and
- the impact of a stronger Canadian dollar;
partially offset by:
- higher North America crude oil and NGL sales volumes; and
- higher crude oil and NGL netbacks.
The increase in cash flow from operations from the third quarter of 2010 was primarily due to:
- higher North America crude oil and NGL sales volumes; and
- higher crude oil and NGL netbacks;
partially offset by:
- the impact of the Horizon suspension net of insurance;
- lower natural gas netbacks;
- higher administration expense;
- lower realized risk management gains; and
- the impact of a stronger Canadian dollar.
The increase in cash flow from operations from the prior quarter was due to:
- the recommencement of production at Horizon and insurance;
- realized risk management gains; and
- the impact of a weaker Canadian dollar;
partially offset by lower crude oil and NGL netbacks.
Total production before royalties for the nine months ended September 30, 2011 decreased 8% to 578,618 BOE/d from 627,052 BOE/d for the nine months ended September 30, 2010. Total production before royalties for the third quarter of 2011 decreased 1% to 612,575 BOE/d from 621,284 BOE/d for the third quarter of 2010 and increased 10% from 556,539 BOE/d for the prior quarter. Production for the third quarter of 2011 was within the Company's previously issued guidance.
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 seasonal 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.
- 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 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, and the suspension and recommencement of production at both Horizon and the Olowi Field in Offshore Gabon.
- 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 operations at Horizon and the impact of the ramp up of production and asset impairments at the Olowi Field in Offshore Gabon.
- Share-based compensation - Fluctuations due to the mark-to-market movements 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 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 (recovery) include statutory tax rate and other legislative changes substantively enacted or 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$95.52 per bbl for the nine months ended September 30, 2011, an increase of 23% from US$77.65 per bbl for the nine months ended September 30, 2010. WTI averaged US$89.81 per bbl for the third quarter of 2011, an increase of 18% from US$76.21 per bbl for the third quarter of 2010, and a decrease of 12% from US$102.55 per bbl for the prior quarter. The decrease in the WTI benchmark price for the third quarter of 2011 compared to the prior quarter was due to the continued high inventory levels of crude oil at Cushing, the relative strength of the US dollar, and the impact of increased supply of light crude oil from the Bakken and Eagleford shale plays. The higher Dated Brent ("Brent") pricing relative to WTI in 2011 from the comparable periods in 2010 was due to the limited pipeline capacity between Petroleum Administration for Defence Districts II ("PADD II") and the United States Gulf Coast. This logistical constraint prevents lower WTI priced barrels delivered into the PADD II from obtaining United States Gulf Coast Brent-based pricing.
Crude oil sales contracts for the Company's North Sea and Offshore Africa segments are typically based on Brent pricing, which is more representative of international markets and overall world supply and demand. Brent averaged US$111.96 per bbl for the nine months ended September 30, 2011, an increase of 45% compared to US$77.15 per bbl for the nine months ended September 30, 2010. Brent averaged US$113.46 per bbl for the third quarter of 2011, an increase of 48% compared to US$76.85 per bbl for the third quarter of 2010 and a decrease of 3% from US$117.33 per bbl for the prior quarter.
The Western Canadian Select ("WCS") Heavy Differential averaged 20% for the nine months ended September 30, 2011 compared to 17% for the nine months ended September 30, 2010. The WCS Heavy Differential widened from the comparable period in 2010 partially due to the impact 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 20% for the third quarter of 2011 and the third quarter of 2010, compared to 17% for the prior quarter. The WCS Heavy Differential widened in the third quarter of 2011, compared to the prior quarter, partially due to the impact of unplanned outages at upgrading facilities.
The Company uses condensate as a blending diluent for heavy crude oil pipeline shipments. During 2011, condensate prices traded at a premium to WTI.
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$4.23 per MMBtu for the nine months ended September 30, 2011, a decrease of 8% from US$4.62 per MMBtu for the nine months ended September 30, 2010. NYMEX natural gas prices averaged US$4.19 per MMBtu for the third quarter of 2011, a decrease of 5% from US$4.42 per MMBtu for the third quarter of 2010, and 4% from US$4.36 per MMBtu for the prior quarter.
AECO natural gas prices for the nine months ended September 30, 2011 averaged $3.55 per GJ, a decrease of 13% from $4.08 per GJ for the nine months ended September 30, 2010. AECO natural gas prices for the third quarter of 2011 averaged $3.53 per GJ and were comparable to the third quarter of 2010 and the prior quarter.
Overall natural 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 nine months ended September 30, 2011 decreased 12% to 370,439 bbl/d from 420,319 bbl/d for the nine months ended September 30, 2010. Crude oil and NGLs production for the third quarter of 2011 decreased 2% to 403,900 bbl/d from 411,585 bbl/d for the third quarter of 2010, and increased 15% from 349,915 bbl/d for the prior quarter. The decrease from the comparable periods in 2010 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. The increase from the prior quarter was primarily due to the recommencement of production at Horizon. Crude oil and NGLs production in the third quarter of 2011 was within the Company's previously issued guidance of 373,000 to 414,000 bbl/d.
Natural gas production for the nine months ended September 30, 2011 averaged 1,249 MMcf/d compared to 1,240 MMcf/d for the nine months ended September 30, 2010. Natural gas production for the third quarter of 2011 averaged 1,252 MMcf/d, comparable to production of 1,258 MMcf/d in the third quarter of 2010, and increased 1% compared to 1,240 MMcf/d for the prior quarter. The increase in natural gas production from the nine months ended September 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 third quarter of 2011 was within the Company's previously issued guidance of 1,230 to 1,255 MMcf/d.
For 2011, revised annual production guidance is targeted to average between 385,000 and 393,000 bbl/d of crude oil and NGLs and between 1,256 and 1,263 MMcf/d of natural gas. Fourth quarter 2011 production guidance is targeted to average between 430,000 and 461,000 bbl/d of crude oil and NGLs and between 1,279 and 1,304 MMcf/d of natural gas.
North America - Exploration and Production
North America crude oil and NGLs production for the nine months ended September 30, 2011 increased 12% to average 296,892 bbl/d from 265,125 bbl/d for the nine months ended September 30, 2010. For the third quarter of 2011, crude oil and NGLs production increased 14% to average 304,671 bbl/d, compared to 267,177 bbl/d for the third quarter of 2010, and increased 3% compared to 295,715 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, the cyclic nature of the Company's thermal operations. The prior quarter was also impacted by the temporary production curtailments of certain fields, including Pelican Lake, due to forest fires in North Central Alberta and flooding in South East Saskatchewan. Production of crude oil and NGLs was within the Company's previously issued guidance of 295,000 bbl/d to 310,000 bbl/d for the third quarter of 2011.
Natural gas production for the nine months ended September 30, 2011 increased 1% to 1,223 MMcf/d compared to 1,216 MMcf/d for the nine months ended September 30, 2010. Natural gas production decreased 1% to 1,226 MMcf/d for the third quarter of 2011 compared to 1,234 MMcf/d in the third quarter of 2010 and increased 1% compared to 1,218 MMcf/d in the prior quarter. Natural gas production for the three and nine months ended September 30, 2011 reflected new production volumes from the Septimus facility in North East British Columbia and the impact of natural gas producing properties acquired during 2010 and 2011, offset by the impact of the 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. Production of natural gas slightly exceeded the Company's previously issued guidance of 1,205 MMcf/d to 1,225 MMcf/d for the third quarter of 2011.
North America - Oil Sands Mining and Upgrading
On August 16, 2011, the Company successfully and safely recommenced operations in the Oil Sands Mining and Upgrading segment. First pipeline deliveries commenced on August 18, 2011. For the third quarter of 2011, production averaged 50,354 bbl/d compared to 83,809 bbl/d in the third quarter of 2010. As a result of the fire at Horizon's primary upgrading coking plant on January 6, 2011, and the resulting suspension of production, production averaged 19,365 bbl/d for the nine months ended September 30, 2011, compared to 90,240 bbl/d for the nine months ended September 30, 2010. There was no production in the prior quarter. Production averaged 108,000 bbl/day for the month of September 2011.
North Sea
North Sea crude oil production for the nine months ended September 30, 2011 decreased 8% to 31,077 bbl/d from 33,828 bbl/d for the nine months ended September 30, 2010. Third quarter 2011 North Sea crude oil production decreased 3% to 26,350 bbl/d from 27,045 bbl/d for the third quarter of 2010, and decreased 20% from 32,866 bbl/d for the prior quarter. The decrease in production volumes from the comparable periods in 2010 and the prior quarter was due to natural field declines and timing of scheduled maintenance shutdowns. The maintenance shutdowns were completed on time and on budget. Production in the third quarter of 2011 was within the Company's previously issued guidance of 24,000 bbl/d to 27,000 bbl/d.
Offshore Africa
Offshore Africa crude oil production decreased 26% to 23,105 bbl/d for the nine months ended September 30, 2011 from 31,126 bbl/d for the nine months ended September 30, 2010. Third quarter crude oil production averaged 22,525 bbl/d, decreasing 33% from 33,554 bbl/d for the third quarter of 2010 and increasing 6% from 21,334 bbl/d for the prior quarter. The decrease in production volumes from the comparable periods in 2010 was due to natural field declines and the temporary suspension of production at the Olowi Field, Gabon as a result of a failure in the midwater arch. Olowi production was fully reinstated in mid-August, ahead of plan, resulting in production in the third quarter slightly exceeding the Company's previously issued guidance of 19,000 bbl/d to 22,000 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 12% to average $69.21 per bbl for the nine months ended September 30, 2011 from $61.79 per bbl for the nine months ended September 30, 2010. North America realized crude oil prices averaged $67.81 per bbl for the third quarter of 2011, an increase of 15% compared to $59.13 per bbl for the third quarter of 2010 and a decrease of 13% compared to $77.62 per bbl for the prior quarter. The increase in prices for the three and nine months ended September 30, 2011 from the comparable periods 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 decrease in prices for the three months ended September 30, 2011 compared to the prior quarter was primarily a result of the lower benchmark WTI pricing and the widening WCS Heavy Differential partially offset by the impact of a weaker Canadian dollar relative to the US dollar. The Company continues to focus on its crude oil blending marketing strategy, and in the third quarter of 2011 contributed approximately 139,000 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 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 Company and the partnership and approval of the final resulting tolls. Board sanction is currently targeted for 2012.
North America realized natural gas prices decreased 12% to average $3.73 per Mcf for the nine months ended September 30, 2011 from $4.23 per Mcf for the nine months ended September 30, 2010. North America realized natural gas prices decreased 1% to average $3.67 per Mcf for the third quarter of 2011, compared to $3.70 per Mcf in the third quarter of 2010, and decreased 2% compared to $3.76 per Mcf for the prior quarter. The decrease in natural gas prices from the comparable periods in 2010 was primarily related to the impact of strong supply from US shale projects, 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 $108.18 per bbl for the nine months ended September 30, 2011 from $80.40 per bbl for the nine months ended September 30, 2010. Realized crude oil prices averaged $109.28 per bbl for the third quarter of 2011, an increase of 34% from $81.47 per bbl for the third quarter of 2010, and decreased 3% from $112.32 per bbl for the prior quarter. The fluctuations in realized crude oil prices in the North Sea from the comparable periods in 2010 was primarily the result of fluctuations in Brent benchmark pricing, partially offset by the impact of the stronger Canadian dollar.
Offshore Africa
Offshore Africa realized crude oil prices increased 36% to average $106.93 per bbl for the nine months ended September 30, 2011 from $78.34 per bbl for the nine months ended September 30, 2010. Realized crude oil prices averaged $114.44 per bbl for the third quarter of 2011, an increase of 48% from $77.32 per bbl for the third quarter of 2010, and an increase of 4% from $110.42 per bbl in the prior quarter. The fluctuations in realized crude oil prices in Offshore Africa from the comparable periods in 2010 was primarily the result of fluctuations in Brent benchmark pricing, partially offset by the impact of the stronger Canadian dollar.
North America
North America royalties for the nine months ended September 30, 2011 compared to 2010 reflected benchmark commodity prices.
Crude oil and NGLs royalties averaged approximately 17% of product sales for the third quarter of 2011 compared to 18% for the third quarter of 2010 and 17% for the prior quarter. Crude oil and NGLs royalties per bbl are anticipated to average 17% to 19% of product sales for 2011.
Natural gas royalties averaged approximately 4% of product sales for the third quarter of 2011, compared to 3% for the third quarter of 2010 and 6% for the prior quarter. The decrease in natural gas royalty rates from the prior quarter was primarily due to gas cost allowance adjustments recorded in the prior 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 18% for the third quarter of 2011 compared to 9% for the third quarter of 2010 and 1% for the prior quarter. The increase in royalties from the third quarter of 2010 and the prior quarter was due to payout of the Baobab Field during the second quarter of 2011. The increase in royalties from the prior quarter also reflected royalty adjustments related to the Baobab and Espoir Fields in the second quarter. Offshore Africa royalty rates are anticipated to average 10% to 12% for 2011.
North America
North America crude oil and NGLs production expense for the nine months ended September 30, 2011 increased 4% to $12.84 per bbl from $12.40 per bbl for the nine months ended September 30, 2010. North America crude oil and NGLs production expense for the third quarter of 2011 increased 8% to $13.38 per bbl from $12.41 per bbl for the third quarter of 2010 and increased 4% from $12.86 per bbl for the prior quarter. The increase in production expense per barrel from the third quarter of 2010 and the prior quarter was a result of higher overall service costs relating to heavy crude oil production and 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 nine months ended September 30, 2011 increased 5% to $1.13 per Mcf from $1.08 per Mcf for the nine months ended September 30, 2010. North America natural gas production expense for the third quarter of 2011 averaged $1.13 per Mcf and increased 9% compared to $1.04 per Mcf for the third quarter of 2010 and increased 4% compared to $1.09 per Mcf for the prior quarter. Natural gas production expense increased from the comparable periods 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. North America natural gas production expense is anticipated to average $1.08 to $1.14 per Mcf for 2011.
North Sea
North Sea crude oil production expense for the nine months ended September 30, 2011 increased 26% to $37.26 per bbl from $29.61 per bbl for the nine months ended September 30, 2010. North Sea crude oil production expense for the third quarter of 2011 increased 12% to $49.72 per bbl from $44.45 per bbl for the third quarter of 2010 and increased 45% from $34.20 per bbl for the prior quarter. Production expense increased on a per barrel basis from the comparable periods in 2010 due to lower volumes on relatively fixed costs and increased fuel prices. Production expense increased from the prior quarter due to the impact of planned turnarounds. Production expense is anticipated to average $37.00 to $38.00 per bbl for 2011.
Offshore Africa
Offshore Africa crude oil production expense for the nine months ended September 30, 2011 increased 34% to $19.99 per bbl from $14.95 per bbl for the nine months ended September 30, 2010. Offshore Africa crude oil production expense for the third quarter of 2011 averaged $19.91 per bbl, an increase of 46% compared to $13.66 per bbl for the third quarter of 2010 and a decrease of 7% compared to $21.36 per bbl for the prior quarter. Production expense increased on a per barrel basis from the comparable periods in 2010 due to lower volumes on relatively fixed costs and due to planned turnarounds. Production expense for the third quarter of 2011 was lower than the prior quarter due to the timing of liftings for each field. Production expense is anticipated to average $21.00 to $22.00 per bbl for 2011.
Depletion, depreciation and amortization expense increased for the nine months ended September 30, 2011 compared to 2010 due to higher production in North America and an increase in the estimated futu
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Datum: 03.11.2011 - 09:00 Uhr
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News-ID 83450
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