Canadian Natural Resources Limited Announces 2013 First Quarter Results
(firmenpresse) - CALGARY, ALBERTA -- (Marketwired) -- 05/02/13 -- Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ)
Commenting on first quarter results, Steve Laut, President of Canadian Natural stated, "Overall this has been an excellent start to the year for Canadian Natural. Operationally it was a successful quarter, with record quarterly production of approximately 681,000 barrels of oil equivalent per day nearing the top end of our guidance and driven by record liquids production of approximately 489,000 barrels per day.
Primary heavy crude oil had record quarterly production volumes of approximately 133,000 barrels of crude oil per day as a result of a focused heavy crude oil drilling program. This is the ninth consecutive quarter of record heavy crude oil production, keeping us on track for our targeted 13% heavy crude oil production growth in 2013. Additionally, natural gas, thermal in situ bitumen, Pelican Lake heavy crude oil, Horizon SCO, light crude oil and NGLs production volumes all delivered as expected.
Canadian Natural's thermal in situ oil sands projects had monthly average production in January of approximately 127,600 barrels of bitumen per day before entering the steam cycle in February. Our 40,000 barrels per day Kirby South Phase 1 thermal in situ oil sands project is on cost and ahead of schedule with first steam-in now targeted for the third quarter of 2013, ahead of our original plan of November 2013.
Our Horizon project achieved strong, reliable production volumes in the first quarter of 2013, averaging approximately 109,000 barrels per day, with April 2013 averaging approximately 104,000 barrels per day. Horizon has seen steady production volumes and sustained increases in reliability over the last year as we focus on an enhanced maintenance strategy and operational discipline. Reliability is expected to further increase as we move through the year with a step change in production performance after our first major turnaround. The turnaround commenced April 30, 2013 and is scheduled for 24 days.
Our Company remains well balanced with a large resource base, strong technical expertise and significant financial resources. The prudent development of these diverse assets will enable us to continue to deliver premium value and defined growth. We continue to execute on our strategy of focusing on projects which maximize returns to our shareholders in the near-, mid- and long-term."
Canadian Natural's Chief Financial Officer, Corey Bieber, continued, "Canadian Natural has a balanced portfolio of high quality assets and our cash flow remains robust which helps us deliver value to our shareholders in any commodity price cycle. As we anticipated, the industry saw a tightening of both heavy crude oil differentials and Brent-WTI differentials after the first quarter of 2013, which is resulting in more favorable price realizations for Canadian Natural.
Returning funds to the Company's shareholders is an important part of our balanced approach to capital allocation along with continued production growth and development of our high quality, long life assets. Dividends have grown for 13 consecutive years and, when combined with share repurchases, represent a 38% compound annual growth rate in funds returned to shareholders since 2008. In 2013, year to date, we have purchased 2,965,700 common shares under the Normal Course Issuer Bid at a weighted average price of $32.12 per common share."
QUARTERLY HIGHLIGHTS
(1) Adjusted net earnings from operations is a non-GAAP measure that the Company utilizes to evaluate its performance. The derivation of this measure is discussed in the Management's Discussion and Analysis ("MD&A").
(2) Cash flow from operations is a non-GAAP measure that the Company considers key as it demonstrates the Company's ability to fund capital reinvestment and debt repayment. The derivation of this measure is discussed in the MD&A.
(3) A barrel of oil equivalent ("BOE") is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") 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.
- Canadian Natural generated cash flow from operations of approximately $1.57 billion in Q1/13 compared to approximately $1.28 billion in Q1/12 and $1.55 billion in Q4/12. The increase in cash flow from the Q4/12 reflects higher synthetic crude oil ("SCO") sales volumes in the Oil Sands Mining and Upgrading segment offset by lower netbacks from the Exploration and Production segment. Adjusted net earnings from operations in Q1/13 increased to $401 million compared to $300 million in Q1/12 and $359 million in Q4/12. Changes in adjusted net earnings primarily reflect the changes in cash flow from operations.
- Total production for Q1/13 averaged 680,844 BOE/d up 11% and 3% from Q1/12 and Q4/12 levels respectively, and crude oil and NGLs production averaged 489,157 bbl/d in Q1/13, up 24% and 4% from Q1/12 and Q4/12 levels respectively, both representing quarterly production records for the Company.
- The increase in total production over the previous quarter reflects the positive results of a disciplined execution strategy driven by strong performance across the asset base, with:
-- record primary heavy crude oil production;
-- increased production from Horizon SCO, Pelican Lake heavy crude oil, light crude oil and NGLs, and natural gas; and
-- strong thermal in situ bitumen production.
- In Q1/13, primary heavy crude oil operations achieved record quarterly production of approximately 133,000 bbl/d. Primary heavy crude oil production is up 11% and 2% from Q1/12 and Q4/12 respectively. This record quarterly production will contribute to the annual primary heavy crude oil production growth which is projected to increase 13% from 2012 levels. Canadian Natural drilled 226 net primary heavy crude oil wells in Q1/13, 39 of which were in Woodenhouse. The Company is targeting to drill a total of 890 net primary heavy crude oil wells in 2013.
- In Q1/13, Pelican Lake reservoir performance continued to be very positive, as expected, with production averaging over 38,000 bbl/d on a restricted basis. The Company targets to complete construction of a new battery at Pelican Lake in June 2013, which will alleviate current production constraints and enable a step increase in Pelican Lake and Woodenhouse production volumes through the second half of 2013. Annual production guidance for Pelican Lake heavy crude oil remains unchanged and is targeted to range from 46,000 bbl/d to 50,000 bbl/d.
- Q1/13 thermal in situ oil sands production volumes averaged approximately 109,000 bbl/d. With increased drilling and operational efficiencies the production fluctuations between the peak and the trough of the thermal in situ production cycles are narrowing. The Company targets Q2/13 thermal in situ production to range between 92,000 to 100,000 bbl/d of bitumen.
- Canadian Natural's Primrose thermal in situ property generates returns amongst the highest in the Company's portfolio. All-in operating costs are below $11.00/bbl and capital costs to grow production volumes through pad adds are approximately $13,000/bbl/d. The Company targets to drill 100 to 120 wells per year at Primrose, which will allow Canadian Natural to maintain production levels in the range of 120,000 bbl/d to 125,000 bbl/d for a period of 5 to 10 years. Engineering studies are being undertaken in 2013 to evaluate the expansion of the Primrose facilities to accelerate the development of these highly cost-effective pad additions. Annual thermal bitumen production at Primrose is targeted to grow by 5% in 2013 over 2012 levels.
- Kirby South Phase 1, the next step in the Company's well defined thermal growth plan, is on budget and ahead of schedule with first steam-in now targeted for Q3/13, ahead of the originally scheduled steam-in date of November 2013. Production is targeted to grow to 40,000 bbl/d through 2014.
- Horizon SCO production averaged approximately 109,000 bbl/d in Q1/13, an increase of 136% from Q1/12 and 31% from Q4/12 levels. April 2013 production averaged approximately 104,000 bbl/d. Safe, steady, and reliable operations continue to be a priority at Horizon. Annual SCO production is targeted to range from 100,000 bbl/d to 108,000 bbl/d in 2013 including the production impact of the planned 24 day turnaround now underway at Horizon. Completion of the turnaround should result in increased reliability and consistent production going forward at Horizon.
- The staged expansion to 250,000 bbl/d of SCO production capacity at Horizon continues to be successful as construction costs to date continue at or below cost estimates. The Horizon expansion continues to deliver capital efficiencies as we maintain a flexible schedule and execution strategy.
- At Septimus, the Company's liquids rich natural gas Montney play, drilling and facility expansion is ahead of schedule and on budget. Upon completion of the facility expansion in Q3/13, natural gas sales levels from Septimus are targeted to increase to 125 MMcf/d, yielding 12,200 bbl/d of liquids up from current levels of approximately 60 MMcf/d and approximately 5,600 bbl/d of liquids.
- Canadian Natural purchased 965,700 common shares during the quarter for cancellation at a weighted average price of $32.72 per common share. Subsequent to March 31, 2013, the Company purchased an additional 2,000,000 common shares at a weighted average price of $31.83 per common share.
- In addition, the Company's Board of Directors have directed Management to continue with an active program, subject to market conditions, to purchase for cancellation common shares under the Company's Normal Course Issuer Bid at or above the levels of shares purchased in financial year 2012, which exceeded 11,000,000 shares.
- Canadian Natural declared a quarterly cash dividend on common shares of C$0.125 per share payable on July 1, 2013, up 19% from the dividend paid at the same time in 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 and operating 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 and 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 Exploration and Production
- North America crude oil and NGLs production averaged 236,600 bbl/d in Q1/13, an increase of 5% and 3% from Q1/12 and Q4/12 levels respectively.
- Canadian Natural drilled 226 net primary heavy crude oil wells in Q1/13, 39 of which were located in the Woodenhouse area outside of the traditional primary heavy crude oil fairway. Canadian Natural's primary heavy crude oil continues to provide strong netbacks and the highest return on capital in the Company's portfolio of diverse and balanced assets. In Q1/13 primary heavy crude oil operations achieved record production volumes of approximately 133,000 bbl/d, resulting in the ninth consecutive quarter of record primary heavy crude oil production volumes, contributing to the targeted 13% primary heavy crude oil production growth in 2013. Another 115 net primary heavy crude oil wells are planned for Q2/13.
- During Q1/13, Pelican Lake reservoir performance remained strong. Facility optimizations allowed the Company to access excess production capacity, enabling total production to exceed 38,000 bbl/d. Recent production volumes at Pelican Lake have been restricted due to facility constraints. In addition, production volumes from the primary heavy crude oil area of Woodenhouse were also restricted by such facility constraints as they utilize Pelican Lake processing facilities. Construction of the new battery at Pelican Lake, on track for completion in June 2013, will alleviate facility constraints and enable a step increase in Pelican Lake and Woodenhouse production volumes through the second half of 2013.
- North America light crude oil and NGLs Q1/13 production increased 2% from Q4/12 as this year's drilling program commenced. In 2013, Canadian Natural targets to drill 114 net light crude oil wells, 41 of which are targeting new play developments that were initiated in 2012. The Company continues to advance horizontal multi-frac well technology in pools across its land base.
- Planned drilling activity for Q2/13 includes 127 net crude oil wells, excluding stratigraphic ("strat") and service wells.
Thermal In Situ Oil Sands
- Q1/13 thermal in situ oil sands production volumes averaged approximately 109,000 bbl/d. Due to steaming and production cycles, production is targeted to range between 92,000 and 100,000 bbl/d in Q2/13, and subsequently increase in Q3/13. Canadian Natural targets to increase 2013 thermal in situ production by 5% over 2012 levels, continuing to operate effectively and efficiently, while maintaining industry leading operating costs.
-- Canadian Natural's Primrose property generates returns amongst the highest in the Company's portfolio. All-in operating costs are below $11.00/bbl and capital costs to grow production volumes through pad adds are approximately $13,000/bbl/d. The Company targets to drill 100 to 120 wells per year at Primrose, which will allow Canadian Natural to maintain production levels at Primrose in the range of 120,000 bbl/d to 125,000 bbl/d for a period of 5 to 10 years. Engineering studies are being undertaken in 2013 to evaluate the expansion of the Primrose facilities to accelerate the development of these highly cost-effective pad additions.
-- Kirby South Phase 1 to date remains ahead of plan and on budget. Drilling is on track to complete the seventh and final pad in Q2/13. Focus will shift from construction to commissioning in late Q2/13 with first steam-in now targeted for Q3/13, ahead of the originally scheduled steam-in date of November 2013. Production is targeted to grow to 40,000 bbl/d through 2014.
-- Detailed engineering is progressing for Kirby North Phase 1. As of March 31, 2013, the engineering portion was 45% complete. Construction of the main access road has been completed and site preparation will continue into Q3/13. A drilling program, consisting of 45 strat and 5 observation wells, was completed during Q1/13, confirming resource delineation and pad layouts for Kirby North Phase 1. The full project will be submitted for Board sanctioning in Q3/13, with first steam-in targeted for 2016 and targeted ultimate production levels of 40,000 bbl/d.
-- Kirby South Phase 1 and Kirby North Phase 1 contribute to a targeted total staged expansion of production volumes from the greater Kirby area over time to 140,000 bbl/d, with the overall thermal in situ development plan targeted to increase to 510,000 bbl/d of production capacity.
- Planned drilling activity for Q2/13 includes 27 net thermal in situ wells, excluding strat and service wells.
- During Q1/13, North American natural gas production averaged 1,125 MMcf/d, representing a 12% decrease from Q1/12 levels and a 1% increase from Q4/12 levels. The decrease in production levels year over year was due to expected production declines, reflecting Canadian Natural's strategic decision to allocate capital to higher return crude oil projects. The increase quarter over quarter reflects the resumption of natural gas production volumes as a result of reduced third party facility constraints in Northeast British Columbia, and from minor acquisitions.
- At Septimus, the Company's liquids rich natural gas Montney play, drilling and plant expansion is ahead of schedule and on budget. Canadian Natural drilled 8 net wells in Septimus during Q1/13, and targets to drill 5 more wells in Q2/13. To date, the expansion is on track with first production targeted for July 2013, adding 22 MMcf/d of natural gas sales, bringing total production to 79 MMcf/d of natural gas sales and 7,700 bbl/d of liquids. Production will ultimately grow by August 2013 to the plant expansion capacity of 125 MMcf/d of natural gas sales, yielding 12,200 bbl/d of liquids, up from current levels of approximately 60 MMcf/d and approximately 5,600 bbl/d of liquids, following processing through the plant and deep cut facilities.
- Canadian Natural has a dominant Montney land position with over one million high quality net acres, the largest in the industry. In Q1/13 the Company commenced the process to monetize approximately 250,000 net acres (approximately 390 net sections) of its Montney land base in the liquids rich fairway in the Graham Kobes area of Northeast British Columbia. To maximize the value of this important asset Canadian Natural will consider either an outright sale of the lands or a joint venture partner with LNG expertise to jointly develop the lands. If a transaction is completed, Canadian Natural will continue to have one of the largest undeveloped Montney land bases in Canada with lands contained in the two major areas of Septimus, British Columbia and Northwest Alberta.
International Exploration and Production
- International crude oil production averaged 34,886 bbl/d during the quarter, which was in line with Q4/12 production and at the high end of the Company's previously stated guidance of 31,000 to 35,000 bbl/d. Crude oil production volumes declined 20% from Q1/12 as a result of natural field declines and the cessation of North Sea drilling activity following an increase in the Supplementary Charge Tax Rate in 2011.
- In September 2012, the UK government announced the implementation of the Brownfield Allowance ("BFA"), which allows for a property development allowance on qualifying preapproved field developments. This allowance partially mitigates the impact of previous tax increases. In Q1/13, the Company received approval for a BFA for its Tiffany field development and as a result, Canadian Natural has commenced infill drilling and targets first oil production from this program in Q2/13.
- A further BFA application for a Ninian field development has been submitted, with approval anticipated in Q2/13. If the Ninian BFA and future BFA applications are approved as expected, additional drilling can be undertaken in the North Sea to increase production and lower current operating costs and reverse the declines seen in the UK since the increase in the Supplementary Charge Tax Rate.
- The light crude oil infill drilling program at Espoir, Offshore Africa, originally targeted to commence in late Q2/13, is progressing slower than anticipated due to contractor safety and performance concerns. The Company is actively engaged with the contractor to ensure the drilling program will be conducted safely and efficiently.
- Regarding Canadian Natural's prospective offshore South Africa property, a partner has been selected to jointly conduct exploratory drilling on the property. The Company will provide further details on the partnership terms upon receipt of regulatory approval. Targeted drilling windows are from Q4/13 to Q1/14 and from Q4/14 to Q1/15 and the necessary long-lead equipment has been ordered.
- Exploration work on Block 514 in Côte d'Ivoire, in which Canadian Natural has a 36% working interest, is underway and a seismic program has been completed. The Company believes this block is prospective for deepwater channel/fan structures similar to the Jubilee crude oil discoveries in Ghana and plays elsewhere in offshore Africa.
North America Oil Sands Mining and Upgrading - Horizon
- During Q1/13 Horizon Oil Sands achieved average SCO production of approximately 109,000 bbl/d. Production volumes were 136% higher than Q1/12 levels and 31% higher than the previous quarter as the reliability of the Horizon plant steadily improved as a result of safe, steady, and reliable operations. Horizon production in April averaged approximately 104,000 bbl/d of SCO.
- The first major maintenance turnaround at Horizon commenced April 30, 2013 and is scheduled to last 24 days. 2013 annual guidance remains unchanged at 100,000 bbl/d to 108,000 bbl/d of SCO including the impact of the turnaround. The turnaround will include required inspections, catalyst change outs, exchanger repairs and will address maintenance items to ensure safe, steady and reliable production going forward. A step change in reliability and strong production performance is expected post turnaround.
- The Horizon Phase 2/3 expansion has unique competitive advantages when compared to other mining developments. Horizon has been designed for optimal performance at 250,000 bbl/d, where the Company can leverage prebuilt infrastructure from Phase 1. Increased reliability and redundancy will be achieved upon completion of the Phase 2/3 expansion and significantly lower operating costs will result as large portions of operating costs are fixed. These factors provide sustainable economic incentives when compared to other mining projects.
- Canadian Natural's staged expansion to 250,000 bbl/d of SCO production capacity continues to progress on track. Capital expenditures to date on Phase 2/3 expansion are at or below cost estimates as the Company executes its cost focused strategy. Expansion work at Horizon will ultimately add an additional 140,000 bbl/d of SCO production in a staged, disciplined manner. Horizon provides high quality, long life SCO production without decline for decades.
- An update to the staged Phase 2/3 expansion on an Engineering, Procurement and Construction basis at the end of Q1/13 is as follows:
-- Overall Horizon Phase 2/3 expansion is 20% complete.
-- Reliability - Tranche 2 is 88% complete. This project is targeted for completion in late 2013; an additional 5,000 bbl/d of production capacity will be added at completion.
-- Directive 74 includes technological investment and research into tailings management. This project remains on track and is currently 17% complete.
-- Phase 2A is a coker expansion. The expansion is 52% complete, and is targeted to add 10,000 bbl/d of production capacity in 2015.
-- Phase 2B is 11% complete. This phase includes lump sum contracts for major components such as gas/oil hydrotreatment, froth treatment and a hydrogen plant. This phase is targeted to add another 45,000 bbl/d of production capacity in 2016.
-- Phase 3 is on track and engineering is underway. This phase is 11% complete, and includes the addition of supplementary extraction trains. This phase is targeted to increase production capacity by 80,000 bbl/d in 2017.
-- The projects which are currently under construction continue to trend at or below cost estimates.
- Total capital budgeted for the Horizon Phase 2/3 expansion in 2013 is $2.06 billion. Canadian Natural continues to be disciplined and cost driven in the Horizon Phase 2/3 expansion to ensure the expansion continues effectively and efficiently.
MARKETING
(1) West Texas Intermediate ("WTI").
(2) Western Canadian Select ("WCS").
(3) Average crude oil and NGLs pricing excludes SCO. Pricing is net of blending costs and excluding risk management activities.
- The Company uses condensate as a blending diluent for heavy crude oil pipeline shipments. During Q1/13, condensate price premiums to WTI widened, reflecting normal seasonality and overall growth in heavy crude oil diluent blending demand.
- Canadian Natural contributed over 178,000 bbl/d of its heavy crude oil blends to the WCS blend in Q1/13. The Company remains the largest contributor to the WCS blend, accounting for over 57% of the total blend this quarter.
- The WCS heavy crude oil differential ("WCS differential") as a percent of WTI averaged 34% during the quarter compared with 21% in both Q1/12 and Q4/12. The differential widened during Q1/13 was due to the seasonal reduction in the demand for heavy crude oil and as a result of planned and unplanned maintenance at refineries accessible to Canadian heavy crude oil. In April and May 2013, the WCS differential, based on current indicative pricing, narrowed to 25% and 15% respectively, in line with the Company's long term expectations.
- Dated Brent-WTI differentials have narrowed in Q2/13 from Q1/13 levels resulting in better overall pricing relative to Brent pricing for Canadian Natural's North American crude oil production, which is typically benchmarked to WTI.
(i) Based on current indicative pricing as at April 30, 2013.
- During Q4/12, the Company entered into a 20 year transportation agreement to ship 75,000 bbl/d of crude oil on the proposed Kinder Morgan Trans Mountain Expansion from Edmonton, Alberta to Vancouver, British Columbia. The regulatory approval process will begin in 2013 with a planned in-service date in 2017. Additionally, the Company has committed 120,000 bbl/d on the proposed Keystone XL pipeline. This pipeline, when built, will bring Canadian heavy crude oil to the Gulf Coast where underutilized heavy oil refining capacity exists.
NORTH WEST REDWATER UPGRADING AND REFINING
In Q1/13 work continued on the North West Redwater refinery and completion is targeted for mid-2016. The North West Redwater refinery asset strengthens the Company's position by providing a competitive return on investment and by adding 50,000 bbl/d of bitumen conversion capacity in Alberta which will help reduce volatility in pricing all Western Canadian heavy crude oil.
FINANCIAL REVIEW
The Company continues to implement proven strategies and its disciplined approach to capital allocation. As a result, the financial position of Canadian Natural remains strong. Canadian Natural's cash flow generation, credit facilities, 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 near-, mid- and long-term.
- The Company's strategy is to maintain a diverse portfolio balanced across various commodity types. The Company achieved production of 680,844 BOE/d for Q1/13 with over 97% of production located in G8 countries.
- Canadian Natural has a strong balance sheet with debt to book capitalization of 28% and debt to EBITDA of 1.2x. At March 31, 2013, long-term debt amounted to $9.3 billion.
- In Q1/13 the Company initiated a US commercial paper program for short-term borrowing. This program will facilitate lower financing costs and provides a diversification of liquidity which further strengthens the financial stability and flexibility of the Company.
- Canadian Natural maintains significant financial stability and liquidity represented by approximately $2.4 billion, net of commercial paper issued, of available credit under its bank credit facilities.
- The Company's commodity hedging program protects investment returns, ensures ongoing balance sheet strength and supports the Company's cash flow for its capital expenditure programs. Approximately 52% of forecasted 2013 crude oil volumes are currently hedged using price collars and physical crude oil sales contracts with fixed WCS differentials. Through the use of collars, the Company has hedged 250,000 bbl/d of crude oil volumes in Q2/13 to Q4/13. To partially mitigate its exposure to widening heavy crude oil differentials, the Company has entered into physical crude oil sales contracts with weighted average fixed WCS differentials as follows: 9,300 bbl/d in Q2/13 at US$19.98/bbl; 11,000 bbl/d in the Q3/13 at US$21.04/bbl; and 8,000 bbl/d in Q4/13 at US$21.19/bbl. Details of the Company's commodity hedging program can be found on the Company's website at .
- Subsequent to Q1/13, Toronto Stock Exchange accepted notice of Canadian Natural's Normal Course Issuer Bid through 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 2013 and ending April 2014, purchase for cancellation on Toronto Stock Exchange and the New York Stock Exchange up to 54,635,116 common shares.
- Canadian Natural purchased 965,700 common shares during the quarter for cancellation at a weighted average price of $32.72 per common share. Subsequent to March 31, 2013, the Company purchased an additional 2,000,000 common shares at a weighted average price of $31.83 per common share.
- In addition, the Company's Board of Directors have directed Management to continue with an active program, subject to market conditions, to purchase for cancellation common shares under the Company's Normal Course Issuer Bid at or above the levels of shares purchased in 2012, which exceeded 11,000,000 shares.
- Canadian Natural declared a quarterly cash dividend on common shares of C$0.125 per share payable on July 1, 2013.
OUTLOOK
The Company forecasts 2013 production levels before royalties to average between 1,085 and 1,145 MMcf/d of natural gas and between 482,000 and 513,000 bbl/d of crude oil and NGLs. Q2/13 production guidance before royalties is forecast to average between 1,090 and 1,110 MMcf/d of natural gas and between 435,000 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 .
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", "proposed" 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, 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 expansions, Primrose thermal projects, Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, construction of the proposed Keystone XL Pipeline from Hardisty, Alberta to the US Gulf Coast, the proposed Kinder Morgan Trans Mountain pipeline expansion from Edmonton, Alberta to Vancouver, British Columbia, 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, natural gas and natural gas liquids ("NGLs") 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 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, 2013 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2012.
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, 2013 and this MD&A have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board. 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 ("Mcf") of natural gas to one barrel ("bbl") 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 and 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 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, 2013 in relation to the first quarter of 2012 and the fourth quarter of 2012. The accompanying tables form an integral part of this MD&A. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2012, is available on SEDAR at , and on EDGAR at . This MD&A is dated May 2, 2013.
(1) Adjusted net earnings from operations is a non-GAAP measure that represents net earnings adjusted for certain items of a non-operational nature. The Company evaluates its performance based on adjusted net earnings from operations. The reconciliation "Adjusted Net Earnings from Operations" presents the after-tax effects of certain items of a non-operational nature that are included in the Company's financial results. Adjusted net earnings from operations may not be comparable to similar measures presented by other companies.
(2) Cash flow from operations is a non-GAAP measure that represents net earnings adjusted for non-cash items before working capital adjustments. The Company evaluates its performance based on cash flow from operations. The Company considers cash flow from operations a key measure as it demonstrates the Company's ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The reconciliation "Cash Flow from Operations" presents certain non-cash items that are included in the Company's financial results. Cash flow from operations may not be comparable to similar measures presented by other companies.
(1) The Company's employee stock option plan provides for a cash payment option. Accordingly, the fair value of the outstanding vested options is recorded as a liability on the Company's balance sheets and periodic changes in the fair value are recognized in net earnings or are capitalized to Oil Sands Mining and Upgrading construction costs.
(2) Derivative financial instruments are recorded at fair value on the balance sheets, with changes in the fair value of non-designated hedges recognized in net earnings. The amounts ultimately realized may be materially different than reflected in the financial statements due to changes in prices of the underlying items hedged, primarily crude oil and natural gas.
(3) Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, partially offset by the impact of cross currency swaps, and are recognized in net earnings.
(4) During the first quarter of 2013, the Company repaid US$400 million of 5.15% unsecured notes. During the fourth quarter of 2012, the Company repaid US$350 million of 5.45% unsecured notes.
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
Net earnings for the first quarter of 2013 were $213 million compared with $427 million for the first quarter of 2012 and $352 million for the fourth quarter of 2012. Net earnings for the first quarter of 2013 included net after-tax expenses of $188 million related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, and the impact of a realized foreign exchange gain on repayment of long-term debt compared with net after-tax income of $127 million for the first quarter of 2012 and net after-tax expenses of $7 million for the fourth quarter of 2012. Excluding these items, adjusted net earnings from operations for the first quarter of 2013 were $401 million compared with $300 million for the first quarter of 2012 and $359 million for the fourth quarter of 2012.
The increase in adjusted net earnings for the first quarter of 2013 from the first quarter of 2012 was primarily due to:
- higher crude oil and synthetic crude oil ("SCO") sales volumes in the North America and Oil Sands Mining and Upgrading segments;
- higher realized natural gas netbacks; and
- higher realized risk management gains;
partially offset by:
- lower crude oil and NGLs netbacks;
- lower natural gas sales volumes; and
- higher depletion, depreciation and amortization expense.
The increase in adjusted net earnings for the first quarter of 2013 from the fourth quarter of 2012 was primarily due to:
- higher SCO sales volumes in the Oil Sands Mining and Upgrading segment;
- higher realized SCO prices;
- higher realized risk management gains;
- lower depletion, depreciation and amortization expense; and
- the impact of a weaker Canadian dollar;
partially offset by:
- lower crude oil and NGLs sales volumes and netbacks.
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 2013 was $1,571 million compared with $1,280 million for the first quarter of 2012 and $1,548 million for the fourth quarter of 2012. The increase in cash flow from operations from the comparable periods was primarily due to the factors noted above relating to the fluctuations in adjusted net earnings, excluding depletion, depreciation and amortization expense, as well as due to the impact of cash taxes.
Total production before royalties for the first quarter of 2013 increased 11% to 680,844 BOE/d from 612,279 BOE/d for the first quarter of 2012 and increased 3% from 658,973 BOE/d for the fourth quarter of 2012.
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 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 from West Texas Intermediate reference location at Cushing, Oklahoma ("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.
- 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, the record heavy crude oil drilling program, 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, shut-in natural gas production due to pricing 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 in 2011 that had 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, asset retirement obligations, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company's proved undeveloped reserves, and the impact of the suspension and recommencement of production at Horizon.
- 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 also 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$94.34 per bbl for the first quarter of 2013, a decrease of 8% from US$102.94 per bbl for the first quarter of 2012, and an increase of 7% from US$88.20 per bbl for the fourth quarter of 2012. The decrease in WTI pricing for the first quarter of 2013 from the first quarter of 2012 was reflective of the European debt crisis, political instability in the Middle East and lower than expected growth in Asian demand. The increase in WTI pricing from the fourth quarter of 2012 reflected increased optimism in the United States economy as well as incremental pipeline capacity to the US Gulf Coast on the Seaway pipeline.
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$112.43 per bbl for the first quarter of 2013, a decrease of 5% from US$118.47 per bbl for the first quarter of 2012, and an increase of 2% from US$110.03 per bbl for the fourth quarter of 2012.
The WCS Heavy Differential averaged 34% for the first quarter of 2013, compared with 21% in the first and fourth quarters of 2012. The WCS Heavy Differential widened in the first quarter of 2013 from the comparable periods as a result of planned and unplanned maintenance at key refineries accessible by Canadian crude oil. The WCS Heavy Differential per barrel narrowed in April 2013 to average US$23.20 per bbl and in May 2013 to average US$13.87 per bbl. To partially mitigate its exposure to widening heavy crude oil differentials, the Company has entered into physical crude oil sales contracts with weighted average fixed WCS differentials as follows: 9,300 bbl/d in the second quarter of 2013 at US$19.98 per bbl; 11,000 bbl/d in the third quarter of 2013 at US$21.04 per bbl; and 8,000 bbl/d in the fourth quarter of 2013 at US$21.19 per bbl.
The Company uses condensate as a blending diluent for heavy crude oil pipeline shipments. During the first quarter of 2013, condensate price premiums to WTI widened, reflecting normal seasonality and overall growth in heavy oil diluent blending demand.
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 economic recovery. The WCS Heavy Differential is expected to continue to reflect seasonal demand fluctuations, changes in transportation logistics, and refinery utilization and shutdowns.
NYMEX natural gas prices averaged US$3.35 per MMBtu for the first quarter of 2013, an increase of 21% from US$2.77 per MMBtu for the first quarter of 2012, and was comparable with the fourth quarter of 2012.
AECO natural gas prices for the first quarter of 2013 averaged $2.92 per GJ, an increase of 22% from $2.39 per GJ for the first quarter of 2012, and an increase of 1% from $2.89 per GJ for the fourth quarter of 2012.
During the first quarter of 2013, natural gas prices continued to recover from the low pricing levels in 2012. Higher utilization of gas fired electric generation, a steady North America production supply forecast and a return to normal winter weather in North America has allowed natural gas inventories to return to seasonal levels.
The Company continues to focus on its crude oil marketing strategy including a blending strategy that expands markets within current pipeline infrastructure, supporting pipeline projects that provide crude oil transportation to new markets, and supporting incremental heavy crude oil conversion capacity. During the fourth quarter of 2012, the Company entered into a 20 year transportation agreement to ship 75,000 bbl/d of crude oil on the proposed Kinder Morgan Trans Mountain Expansion from Edmonton, Alberta to Vancouver, British Columbia. The regulatory approval process will begin in 2013 with a planned in-service date in 2017.
(1) Net of blending costs and excluding risk management activities.
(2) Comparative figures have been adjusted to reflect realized product prices before transportation costs.
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, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil) and SCO.
Crude oil and NGLs production for the first quarter of 2013 increased 24% to 489,157 bbl/d from 395,461 bbl/d for the first quarter of 2012 and increased 4% from 469,964 bbl/d for the fourth quarter of 2012. The increase in production for the first quarter of 2013 compared with the first quarter of 2012 was primarily due to the increase in Horizon production volumes, the impact of a strong heavy crude oil drilling program and the increased production from the Company's cyclic thermal operations. The increase in production from the fourth quarter of 2012 was primarily due to the increase in Horizon production volumes, partially offset by the decrease in production from the Company's cyclic thermal operations. The fluctuations in the Company's thermal production from quarter to quarter were due to the cyclic nature of thermal operations. Crude oil and NGLs production in the first quarter of 2013 was within the Company's previously issued guidance of 471,000 to 495,000 bbl/d.
Natural gas production for the first quarter of 2013 decreased 12% to 1,150 MMcf/d from 1,302 MMcf/d for the first quarter of 2012 and increased 1% from 1,134 MMcf/d for the fourth quarter of 2012. The decrease in natural gas production from the first quarter of 2012 was primarily a result of a strategic reduction of natural gas drilling as the Company allocated capital to higher return crude oil projects, as well as expected production declines. The increase in natural gas production from the fourth quarter of 2012 reflected the resumption of production of certain natural gas volumes that were previously restricted, as well as the impact of natural gas producing properties acquired in the fourth quarter of 2012. Natural gas production in the first quarter of 2013 was at the high end of the Company's previously issued guidance of 1,130 to 1,150 MMcf/d.
For 2013, annual production guidance is targeted to average between 482,000 and 513,000 bbl/d of crude oil and NGLs and between 1,085 and 1,145 MMcf/d of natural gas. Second quarter 2013 production guidance is targeted to average between 435,000 and 461,000 bbl/d of crude oil and NGLs and between 1,090 and 1,110 MMcf/d of natural gas.
North America - Exploration and Production
For the first quarter of 2013, crude oil and NGLs production increased 13% to average 345,489 bbl/d compared with 305,613 bbl/d for the first quarter of 2012 and decreased 2% from 351,983 bbl/d in the fourth quarter of 2012. The increase in crude oil and NGLs production from the first quarter of 2012 was primarily due to the impact of a strong heavy crude oil drilling program and the increased production from the Company's cyclic thermal operations. The decrease from the fourth quarter of 2012 was primarily due to the decrease in production from the Company's cyclic thermal operations. First quarter 2013 production of crude oil and NGLs was within the Company's previously issued guidance of 335,000 to 349,000 bbl/d. Second quarter 2013 production guidance is targeted to average between 326,000 and 342,000 bbl/d for crude oil and NGLs.
Natural gas production decreased 12% to 1,125 MMcf/d for the first quarter of 2013 compared with 1,281 MMcf/d in the first quarter of 2012 and increased 1% from 1,113 MMcf/d for the fourth quarter of 2012. The decrease in natural gas production from the first quarter of 2012 was primarily a result of a strategic reduction of natural gas drilling as the Company allocated capital to higher return crude oil projects, as well as expected production declines. The increase from the fourth quarter of 2012 primarily reflected the resumption of production of certain natural gas volumes which were previously restricted, as well as the impact of natural gas producing properties acquired in the fourth quarter of 2012.
North America - Oil Sands Mining and Upgrading
For the first quarter of 2013, SCO production averaged 108,782 bbl/d compared with 46,090 bbl/d for the first quarter of 2012 and 83,079 bbl/d for the fourth quarter of 2012. First quarter production in 2013 increased from the comparable periods as a result of the Company's strong operating performance and its continued focus on efficient and effective operations. Production of SCO was within the Company's previously issued guidance of 105,000 to 111,000 bbl/d for the first quarter of 2013. Second quarter 2013 production guidance is targeted to average between 77,000 and 83,000 bbl/d due to the impact of the 24 day planned maintenance turnaround in May 2013.
North Sea
For the first quarter of 2013, North Sea crude oil production decreased 19% to 18,774 bbl/d compared with 23,046 bbl/d for the first quarter of 2012, and decreased 2% from 19,140 bbl/d in the fourth quarter of 2012. The decrease in production from the comparable periods was primarily due to natural field declines and a reduction in drilling activities as a result of an increase in the corporate income tax rate in 2011.
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. The FPSO and associated floating storage unit have subsequently been removed from the field and the FPSO is currently undergoing repairs. The extent of the property damage, including associated costs, is not expected to be significant.
Offshore Africa
First quarter 2013 crude oil production averaged 16,112 bbl/d, decreasing 22% from 20,712 bbl/d for the first quarter of 2012 and increasing 2% from 15,762 bbl/d in the fourth quarter of 2012. The decrease in production volumes for the first quarter of 2013 from the first quarter of 2012 was due to natural field declines and lower production from Gabon. The increase in production volumes from the fourth quarter of 2012 was due to the completion of planned turnaround activity at Espoir during the fourth quarter of 2012, partially offset by natural field declines. Late in the first quarter of 2013, the midwater arch at the Olowi field in Gabon was stabilized and production was reinstated. The Company is currently assessing the long-term operability of the midwater arch.
International Guidance
The Company's North Sea and Offshore Africa first quarter 2013 crude oil and NGLs production was within the Company's previously issued guidance of 31,000 to 35,000 bbl/d. Second quarter 2013 production guidance is targeted to average between 32,000 and 36,000 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 FPSOs, as follows:
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending costs and excluding risk management activities.
(3) Comparative figures have been adjusted to reflect realized product prices before transportation costs.
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending costs and excluding risk management activities.
(3) Comparative figures have been adjusted to reflect realized product prices before transportation costs.
North America
North America realized crude oil prices averaged $55.68 per bbl for the first quarter of 2013, a decrease of 27% compared with $76.72 per bbl for the first quarter of 2012 and a decrease of 11% compared with $62.68 per bbl for the fourth quarter of 2012. The decrease in realized crude oil prices for the first quarter of 2013 from the comparable periods was due to the widening of the WCS Heavy Differential and higher diluent blending costs; partially offset by the impact of a weaker Canadian dollar relative to the US dollar as well as fluctuations in WTI benchmark pricing. The Company continues to focus on its crude oil blending marketing strategy and in the first quarter of 2013 contributed approximately 178,000 bbl/d of heavy crude oil blends to the WCS stream.
North America realized natural gas prices increased 29% to average $3.37 per Mcf for the first quarter of 2013 compared with $2.62 per Mcf in the first quarter of 2012, and increased 2% compared with $3.30 per Mcf for the fourth quarter of 2012. The increase in realized natural gas prices for the first quarter of 2013 from the comparable periods was primarily due to higher AECO benchmark pricing related to the impact of higher utilization of gas fired electric generation, a steady North America production supply forecast and a return to normal winter weather in North America.
Comparisons of the prices received in North America Exploration and Production by product type were as follows:
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending costs and excluding risk management activities.
(3) Comparative figures have been adjusted to reflect realized product prices before transportation costs.
North Sea
North Sea realized crude oil prices averaged $114.28 per bbl for the first quarter of 2013, a decrease of 3% fro
Themen in dieser Pressemitteilung:
Unternehmensinformation / Kurzprofil:
Datum: 02.05.2013 - 21:00 Uhr
Sprache: Deutsch
News-ID 255771
Anzahl Zeichen: 0
contact information:
Town:
CALGARY, ALBERTA
Kategorie:
Oil & Gas
Diese Pressemitteilung wurde bisher 226 mal aufgerufen.
Die Pressemitteilung mit dem Titel:
"Canadian Natural Resources Limited Announces 2013 First Quarter Results"
steht unter der journalistisch-redaktionellen Verantwortung von
Canadian Natural Resources Limited (Nachricht senden)
Beachten Sie bitte die weiteren Informationen zum Haftungsauschluß (gemäß TMG - TeleMedianGesetz) und dem Datenschutz (gemäß der DSGVO).
