CALGARY, ALBERTA — (Marketwired) — 11/07/13 — Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ)
Commenting on third quarter results, Steve Laut, President of Canadian Natural stated, “We achieved excellent results this quarter both operationally and financially, which demonstrates our ability to execute on our strategy to deliver premium value and defined growth. Our experienced team, together with our strong and diverse asset base, continues to maximize shareholder value in the near-, mid- and long-term. As a result of this continued strength in the Company–s results and successful execution to date on the Horizon project expansion, the Company–s Board of Directors have increased, commencing with Q4/13, the quarterly dividend to $0.20 per share, an increase of 60% over the previous quarterly dividend, to $0.80 per share per year.
Operationally, it was a successful quarter, with record quarterly production of approximately 703,000 barrels of oil equivalent per day, driven by record liquids production of approximately 509,000 barrels per day. Primary heavy crude oil achieved its eleventh consecutive record quarterly production with volumes of approximately 140,500 barrels of crude oil per day. Additionally, we achieved record Pelican Lake crude oil production, demonstrating the strength of our innovative polymer flood technology in this reservoir.
We achieved many milestones this quarter as we continue to execute on our strategy of focusing on projects which maximize returns to our shareholders. Horizon had strong and reliable production averaging approximately 112,000 barrels of high quality synthetic crude oil per day, with September 2013 production of approximately 117,000 barrels per day. The construction of Horizon Phase 2/3 is physically 30% complete and we are well on our way to deliver a project which provides significant value to our shareholders, without production decline, for decades. Thermal in situ oil sands production was robust at 109,000 barrels of crude oil per day. Our Kirby South SAGD project achieved first steam injection in September, ahead of schedule and on budget. The Septimus plant expansion was completed during the third quarter and is operating at capacity with over 12,200 barrels per day of liquids production and 125 MMcf per day of natural gas production.
The continued prudent development of our assets enables us to generate substantial and growing cash flow which can be allocated to resource development, sustainable dividends, share purchases, opportunistic acquisitions, and debt repayment.”
Canadian Natural–s Chief Financial Officer, Corey Bieber, continued, “Our record cash flow this quarter of approximately $2.45 billion was due to the strong performance of all assets and the robust crude oil price environment. As expected, Canadian Natural achieved strong price realizations with the tightening of both heavy oil differentials and Brent-WTI differentials in the third quarter of 2013. This cash flow generation enables us to effectively manage our balance sheet while maximizing shareholder value and delivering premium value and defined growth.”
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 record quarterly cash flow from operations of approximately $2.45 billion in Q3/13, an increase of 71% compared to approximately $1.43 billion in Q3/12 and an increase of 47% compared to approximately $1.67 billion in Q2/13. The record quarterly cash flow was as a result of higher crude oil and NGLs and synthetic crude oil (“SCO”) netbacks combined with record quarterly liquids production as a result of a high level of activity on heavy crude oil assets, strong Pelican Lake crude oil production, strong thermal in situ oil sands (“thermal in situ”) and Horizon Oil Sands (“Horizon”) production volumes and the successful expansion of the Septimus plant.
– Adjusted net earnings from operations in Q3/13 were $1,009 million, an increase of 186% from $353 million in Q3/12 and an increase of 118% from $462 million in Q2/13. Changes in adjusted net earnings primarily reflect the changes in cash flow from operations.
– Canadian Natural declared a quarterly cash dividend on common shares of C$0.20 per share payable on January 1, 2014, representing a 60% increase over the previous quarterly dividend. This is the fourteenth consecutive year of dividend increases since the Company first paid a dividend in 2001 and a compound annual growth rate of 31% from 2009 when Horizon first commenced production. This dividend reflects the continued strong operational results of the Company and the successful execution to date on the Horizon Phase 2/3 development, both in terms of construction accomplished and cost performance to date and the amount of future contracts that have been awarded. To date, over two-thirds of Horizon project costs have been completed or have moved to the contracting stage.
– Record total production for Q3/13 averaged 702,938 barrels of oil equivalent per day (“BOE/d”). Production volumes exceeded Q3/12 and Q2/13 levels by 5% and 13% respectively, primarily as a result of strong liquids growth across all assets. The quarterly highlights include higher volumes at Horizon as the Company achieved safe, steady and reliable production. Additionally, production volumes increased as a result of a high level of activity on primary heavy crude oil assets, strong Pelican Lake performance, growth in light crude oil and NGLs production and the cyclic nature of thermal in situ, contributing to record liquids production and record total BOE/d production.
– In Q3/13, primary heavy crude oil operations achieved record quarterly production of approximately 140,500 barrels per day (“bbl/d”), the Company–s eleventh consecutive quarter of record primary heavy crude oil production. Primary heavy crude oil production increased 10% and 3% from Q3/12 and Q2/13, respectively, due to strong results from the Company–s drilling program.
– In Q3/13, Pelican Lake operations achieved record quarterly production volumes of greater than 45,500 bbl/d, 9% higher than Q2/13 volumes. Production has increased, as expected, subsequent to the completion of an oil battery in Q2/13 which alleviated production constraints. This is the third consecutive quarter of production increases, which reflects Canadian Natural–s continued success in implementing polymer flooding technology.
– First steam injection was achieved at Kirby South in September 2013, ahead of the originally targeted steam-in date of November 2013. Kirby South, a 100% owned and operated steam assisted gravity drainage (“SAGD”) project, was completed on budget, at a cost of approximately $30,000 per flowing barrel. Steam is currently being circulated in 28 well pairs on 4 pads to initiate the SAGD processes. The well response at Kirby South is performing as expected and production is targeted to grow to 40,000 bbl/d in Q4/14. All evaporators, steam generators and oil treating vessels are in service and the first shipment of crude oil produced from commissioning activities was delivered on November 4, 2013.
– Operating performance at Horizon has been strong since the Company executed its first major turnaround in May 2013. Horizon SCO production for Q3/13 was approximately 112,000 bbl/d, with September 2013 production at approximately 117,000 bbl/d. Canadian Natural expects production reliability at Horizon with Q4/13 production volumes currently targeted to average between 110,000 bbl/d and 115,000 bbl/d.
– At Septimus, the Company–s liquids rich natural gas Montney play, the plant expansion was completed in early Q3/13. During the first week of September 2013, the newly expanded gas plant reached its production capacity of 125 MMcf/d and approximately 12,200 bbl/d of liquids with the completion of new wells. The liquids rich production at Septimus contains high value condensate and NGLs, which significantly contributes to the favorable economics and revenue generation by the Septimus field.
– In Q3/13, Canadian Natural completed the acquisition of Barrick Energy Inc. for approximately $173 million. The production and undeveloped land base is complementary to Canadian Natural–s existing assets and is concentrated in light oil weighted assets with strong netbacks and a long reserve life. This acquisition added approximately 4,200 bbl/d of light crude oil and NGLs and 4 MMcf/d of natural gas production. These assets have been integrated into the Company–s operations and optimization opportunities are underway.
– During the third quarter of 2013, the Company disposed of a 50% interest in its exploration right in South Africa, for net cash consideration of US$255 million, including a recovery of US$14 million of past incurred costs, resulting in an after-tax gain on sale of exploration and evaluation property of $166 million. Further, in the event that a commercial crude oil or natural gas discovery occurs on this exploration right, resulting in the exploration right being converted into a production right, an additional cash payment would be due to the Company at such time, amounting to US$450 million for a commercial crude oil discovery and US$120 million for a commercial natural gas discovery. Long lead equipment has been ordered and the operator is targeting to drill the first exploration well in 2014.
– In Q3/13, TransCanada Corporation announced a successful open season on its Energy East Pipeline project which is anticipated to add 1.1 MMbbl/d of incremental pipeline capacity to the east coast of Canada. Canadian Natural is a strong supporter of this project and has made commitments of 80,000 bbl/d of crude oil. This commitment is in addition to previously announced commitments of crude oil to Keystone XL and Trans Mountain Expansion of 120,000 bbl/d and 75,000 bbl/d, respectively.
– As expected, heavy oil differentials narrowed during the third quarter, resulting in favorable price realizations for the Company. The WCS heavy oil differential (“WCS differential”) as a percent of WTI averaged 16% in Q3/13 compared to 24% in Q3/12 and 20% in Q2/13. The narrowing during this quarter reflects normal seasonality as heavy oil demand increases. Q4/13 indications are wider as a result of market volatility due to infrastructure turnarounds and normal seasonal variation.
– As expected, the Dated Brent to WTI differential narrowed to US$4.53/bbl in Q3/13 compared to US$17.38/bbl in Q3/12 and US$8.21/bbl in Q2/13. Overall pricing relative to Dated Brent pricing for Canadian Natural–s North American crude oil production improved in Q3/13 as a result.
– Year to date, Canadian Natural has purchased for cancellation 9,255,500 common shares at a weighted average price of $31.13 per common share.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural focuses its activities in core regions where the Company owns 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. Furthermore, 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 crude oil and NGLs operations achieved record quarterly production of 256,329 bbl/d in Q3/13, an increase of 11% and 6% from Q3/12 and Q2/13 levels respectively.
– Canadian Natural drilled 253 net primary heavy crude oil wells in Q3/13. Canadian Natural–s primary heavy crude oil continues to provide strong netbacks and a high return on capital in the Company–s portfolio of diverse and balanced assets. In Q3/13 primary heavy crude oil operations achieved record production volumes of approximately 140,500 bbl/d, resulting in the eleventh consecutive quarter of record primary heavy crude oil production volumes. The Company is targeting to drill an additional 252 net primary heavy crude oil wells in Q4/13.
– Woodenhouse achieved record production volumes during Q3/13 averaging approximately 16,000 bbl/d, representing an increase of 19% from Q2/13 levels of approximately 13,500 bbl/d. Subsequent to Q3/13, on October 17, 2013, fuel gas supply to the Woodenhouse operation was interrupted as a result of a third party pipeline issue. Production volumes have been temporarily affected and the Company has acquired an alternative fuel source to substantially mitigate the disruption. Woodenhouse is expected to return to full production rates when the third party restores fuel gas supply.
– Pelican Lake achieved record quarterly crude oil production of approximately 45,500 bbl/d in Q3/13, a 12% increase from Q3/12 and a 9% increase from Q2/13. This is the third consecutive quarter of production increases, which reflects Canadian Natural–s continued success in implementing polymer flooding technology. Eleven net horizontal production wells were drilled during the quarter and an additional 8 net horizontal production wells are targeted to be drilled in Q4/13. Operating costs have continued to decline to approximately $9.45/bbl as production increases and optimization strategies are implemented.
– North America light crude oil and NGLs achieved record quarterly production of approximately 70,300 bbl/d in Q3/13. Production increased 10% from Q2/13, largely as a result of the Barrick acquisition and increased NGLs production associated with the Septimus project expansion. The Company drilled 30 net light crude oil wells in Q3/13 and targets to drill 33 additional net wells in Q4/13. Canadian Natural–s light crude oil drilling program will continue to utilize and advance horizontal multi-frac well technology to access new reserves in pools across the Company–s land base.
– Q3/13 thermal in situ production volumes increased to more than 109,000 bbl/d due to the timing of steaming and production cycles.
– During Q2/13, bitumen emulsion was discovered at surface at 4 separate locations in the Company–s Primrose development area, 3 at Primrose East and 1 at Primrose South. Canadian Natural continues to work with Alberta Environment and Sustainable Resource Development (“AESRD”) on an effective and efficient clean-up. Cleanup of the 3 Primrose East sites is essentially complete and the Primrose South site cleanup is expected to be completed in 2014.
– Canadian Natural continues to work with the Alberta Energy Regulator (“AER”) on the causation review of the bitumen emulsion seepage. Canadian Natural believes the cause of the bitumen emulsion seepage is mechanical failures of wellbores in the vicinity of the 4 impacted locations. The Company has reviewed all the wellbores in the vicinity of each seepage and has prioritized further work to confirm the mechanical failure, pending regulatory approval for surface access.
– The Company–s near term steaming plan at Primrose has been modified as a result of the seepages, with steaming being reduced in certain areas until the causation review with the AER is complete. Canadian Natural believes that reserves recovered from the Primrose area over its life cycle will be substantially unchanged.
– First steam injection was achieved at Kirby South in September 2013, ahead of the originally targeted steam-in date of November 2013. Kirby South, a 100% owned and operated steam assisted gravity drainage (“SAGD”) project, was completed on budget, at a cost of approximately $30,000 per flowing barrel. Steam is currently being circulated in 28 well pairs on 4 pads to initiate the SAGD processes. The well response at Kirby South is performing as expected and production is targeted to grow to 40,000 bbl/d in Q4/14. All evaporators, steam generators and oil treating vessels are in service and the first shipment of crude oil produced from commissioning activities was delivered on November 4, 2013.
– Detailed engineering is progressing for Kirby North Phase 1. As of September 30, 2013, the engineering portion was approximately 80% complete. Site preparation for the project is underway and will continue into Q4/13. The project is targeted for Board sanctioning in Q2/14.
– Kirby South and Kirby North Phase 1 will contribute to a staged expansion plan for the greater Kirby area. The Company targets to increase Kirby area production volumes, over time, to approximately 140,000 bbl/d. Canadian Natural–s current overall thermal in situ development plan targets to increase facility capacity from current levels of approximately 170,000 bbl/d to approximately 510,000 bbl/d in staged increments over the next 15 years.
– Planned drilling activity for Q4/13 includes 35 net thermal in situ wells, excluding strat and service wells.
– During Q3/13, North America natural gas production averaged 1,136 MMcf/d, representing a 4% increase from Q2/13 levels and a 3% decrease from Q3/12 levels. The decrease in production levels year over year was due to natural production declines, reflecting Canadian Natural–s strategic decision to allocate capital to higher return crude oil projects. The increase in production from last quarter was driven by Septimus production and also as a result of the resumption in production after planned maintenance and turnarounds in Q2/13.
– At Septimus, the Company–s liquids rich natural gas Montney play, the plant expansion was completed during Q3/13. During the first week of September 2013, the newly expanded gas plant reached its production capacity of 125 MMcf/d and approximately 12,200 bbl/d of liquids with the completion of new wells. During Q3/13, Canadian Natural drilled 7 net wells at Septimus and the company targets to drill 6 additional net wells in Q4/13, which, when completed, will maximize the utilization of the plant capacity in 2014.
– 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 explore options to monetize approximately 243,000 net acres (approximately 380 net sections) of its Montney land base in the liquids rich fairway in the Graham Kobes area of Northeast British Columbia. The data room opened in Q3/13 and presentations to interested parties are underway and tracking to plan.
International Exploration and Production
– International crude oil production averaged 31,700 bbl/d during the quarter, a 14% decline from Q2/13, primarily due to planned maintenance and turnaround activities undertaken at Tiffany and Ninian South. Crude oil production volumes declined 14% from Q3/12 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. To date Canadian Natural has received approval for two BFAs. The Tiffany field BFA resulted in a two well infill drilling program, which achieved first oil in May 2013. The most recent BFA was awarded for the Company–s Ninian Field development plan, which includes four new production wells, four injectors and two well upgrades. Drilling is targeted to commence in Q4/13.
– Canadian Natural is in the process of obtaining a drilling rig to undertake the light crude oil infill drilling program at Espoir, Cote d–Ivoire. The development of Espoir is now targeted to commence in the second half of 2014 with a 10 well drilling program. This program is targeted to add 5,900 BOE/d of net production when complete.
– Development plans for Baobab are underway with a 7 well drilling program targeting to commence in 2015. This program is targeted to add 11,000 BOE/d of net production.
– Earlier in 2013 Canadian Natural announced the acquisition of two prospective blocks in Cote d–Ivoire which are prospective for deepwater channel/fan structures similar to Jubilee crude oil discoveries in Ghana and plays elsewhere in offshore Africa.
— Block CI-12 is located approximately 35 km west of the Canadian Natural–s current production at Espoir and Baobab and Canadian Natural operates with a 60% working interest. The Company plans to commence a new 3D seismic acquisition in Q4/13. Potential exploration drilling is targeted for 2015.
— Block CI-514 is operated by Total and Canadian Natural has a 36% working interest. A seismic program has been completed and a drilling rig has been contracted to commence drilling in the first half of 2014.
– During the third quarter of 2013, the Company disposed of a 50% interest in its exploration right in South Africa, for net cash consideration of US$255 million, including a recovery of US$14 million of past incurred costs, resulting in an after-tax gain on sale of exploration and evaluation property of $166 million. Further, in the event that a commercial crude oil or natural gas discovery occurs on this exploration right, resulting in the exploration right being converted into a production right, an additional cash payment would be due to the Company at such time, amounting to US$450 million for a commercial crude oil discovery and US$120 million for a commercial natural gas discovery. Long lead equipment has been ordered and the operator is targeting to drill the first exploration well in 2014.
North America Oil Sands Mining and Upgrading – Horizon
– During Q3/13, SCO production averaged approximately 112,000 bbl/d at Horizon Oil Sands, up 65% from the previous quarter as the completion of the Company–s first major maintenance turnaround occurred in May 2013. Horizon SCO production averaged approximately 117,000 bbl/d in September 2013. Subsequent to Q3/13, October production was approximately 105,600 bbl/d of SCO. October production volumes were affected by third party pipeline issues, which limited the supply of fuel gas to the Horizon site for three days, including the ramp down and ramp up of facilities. Q4/13 production guidance is targeted to range from 110,000 bbl/d to 115,000 bbl/d.
– Canadian Natural achieved several key milestones in Q3/13 as the Company continues to deliver on its strategy to transition to a longer life, low decline asset base which provides significant and growing free cash flow. Canadian Natural–s staged expansion to 250,000 bbl/d of SCO production capacity continues to progress on track and below sanctioned costs.
– An update to the staged Phase 2/3 physical completion of expansion at the end of Q3/13 is as follows:
— Overall Horizon Phase 2/3 expansion is 30% physically complete.
— Reliability – Tranche 2 is 91% physically complete and approximately 5% under budget. This phase will increase performance, overall production reliability and the Gas Recovery Unit will recover additional light oil barrels in 2014.
— Directive 74 includes technological investment and research into tailings management. This project remains on track and is physically 22% complete.
— Phase 2A is a coker expansion which will utilize pre-invested infrastructure and equipment to expand the Coker Plant and alleviate the current bottleneck. The expansion is 70% physically complete with current progress tracking ahead of schedule. The coker tie-in was originally scheduled to be completed in mid-2015, however, due to strong construction performance and the early completion of the coker installation, the Company has accelerated the tie-in to September 2014. An increase in Horizon production capacity of approximately 12,000 bbl/d is targeted to occur subsequent to the completion of the coker tie-in.
— Phase 2B is 20% physically complete. This phase expands the capacity of major components such as gas/oil hydrotreatment, froth treatment and the hydrogen plant. This phase is targeted to add another 45,000 bbl/d of production capacity in 2016.
— Phase 3 is on track and on schedule. This phase is 19% physically complete, and includes the addition of supplementary extraction trains. This phase is targeted to increase production capacity by 80,000 bbl/d in 2017 and will result in additional reliability, redundancy and significant operating cost savings.
— The projects currently under construction continue to trend at or below cost estimates.
– Horizon expansion progress has been very good with physical completion of 30% to date compared with only 28% of estimated costs incurred or $3.9 billon. Total project capital budgeted for the Horizon Phase 2/3 expansion in 2013 is approximately $2 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.
– To ensure greater cost certainty, Canadian Natural has negotiated over half of committed capital as lump sum contracts and is in the contract negotiation stage for two-thirds of targeted project capital. To date, Canadian Natural is running 10% below our original cost estimates.
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.
(i)Based on current indicative pricing as at October 31, 2013.
– As expected, heavy oil differentials narrowed during the third quarter, resulting in favorable price realizations for the Company. The WCS differential averaged 16% in Q3/13 compared to 24% in Q3/12 and 20% in Q2/13. The differential narrowed during Q3/13 compared to Q2/13 due to increased seasonal demand for heavy crude oil, increased pipeline capacity resulting from improved pipeline reliability, and lower unplanned maintenance activity at refineries accessible to Canadian heavy crude oil. Q4/13 indications are wider as a result of market volatility due to infrastructure turnarounds and normal seasonal variation.
– Canadian Natural contributed over 166,000 bbl/d of its heavy crude oil blends to the WCS blend in Q3/13. The Company remains the largest contributor to the WCS blend, accounting for over 61% of the total blend this quarter.
– The Company uses condensate as a blending diluent for heavy crude oil pipeline shipments. During Q3/13, condensate price to WTI narrowed to US$1.99/bbl discount compared to US$7.27/bbl premium in Q2/13 reflecting normal seasonality.
– As expected, the Dated Brent to WTI differential narrowed to US$4.53/bbl in Q3/13 compared to US$17.38/bbl in Q3/12 and US$8.21/bbl in Q2/13, reflecting continued debottlenecking of the logistical constraints between Cushing and the Gulf Coast as incremental pipeline capacity continued to grow. Overall pricing relative to Dated Brent pricing for Canadian Natural–s North American crude oil production continues to improve.
– SCO pricing averaged US$109.97/bbl for the Q3/13, an increase of 21% from US$90.84/bbl from Q3/12, and an increase of 11% from US$99.10/bbl from Q2/13. The increase in SCO pricing from the previous periods was primarily due to the increase in benchmark pricing. Q4/13 indications are wider largely as a result of pipeline apportionments.
NORTH WEST REDWATER UPGRADING AND REFINING
During Q3/13 the North West Redwater refinery engineering progressed and preliminary earthwork continued. The North West Redwater team is working toward a final cost control estimate, with the final report targeted for November 15, 2013. At present, Canadian Natural has invested $307 million into the partnership, accounted for using the equity method. The partnership has incurred to date $477 million in debt, of which 25% is attributable to Canadian Natural under a 30 year fee-for-service tolling agreement. The North West Redwater refinery, upon construction, will strengthen 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 pricing volatility in 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 appropriate 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 702,938 BOE/d for Q3/13 with approximately 97% of production located in G8 countries.
– Canadian Natural has a strong balance sheet with debt to book capitalization of 27% and debt to EBITDA of 1.1x at September 30, 2013.
– Canadian Natural maintains significant financial stability and liquidity represented by approximately $2.9 billion of available credit under its bank credit facilities, net of commercial paper issued as at September 30, 2013.
– 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. As at November 5, 2013, 317,000 bbl/d of currently forecasted Q4/13 crude oil volumes and approximately 184,000 bbl/d of 2014 crude oil volumes were hedged using price collars and physical crude oil sales contracts with fixed WCS differentials. Through the use of collars, the Company has hedged approximately 300,000 bbl/d of crude oil volumes in Q4/13, and approximately 175,000 bbl/d of crude oil volumes in 2014 with floors of US$75.00 and US$80.00. 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:
Details of the Company–s commodity hedging program can be found on the Company–s website at .
– Year to date, Canadian Natural has purchased for cancellation 9,255,500 common shares at a weighted average price of $31.13 per common share.
– Canadian Natural declared a quarterly cash dividend on common shares of C$0.20 per share payable on January 1, 2014, an increase of 60% over the previous quarterly dividend. This is the fourteenth consecutive year of dividend increases since the Company first paid a dividend in 2001, with a compound annual growth rate of 24% since that time, and a compound annual growth rate of 31% from 2009 when Horizon first commenced production.
OUTLOOK
For 2013, original annual production guidance was 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. Q4/13 production guidance before royalties is forecast to average between 474,000 and 513,000 bbl/d of crude oil and NGLs and between 1,195 and 1,205 MMcf/d of natural gas. 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, construction of the proposed Energy East pipeline to transport crude oil from Alberta to Quebec and New Brunswick, 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 and nine months ended September 30, 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 September 30, 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 and adjusted depreciation, depletion and amortization are 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 and nine months ended September 30, 2013 in relation to the comparable periods in 2012 and the second quarter of 2013. 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 November 5, 2013.
FINANCIAL HIGHLIGHTS
(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.
Adjusted Net Earnings from Operations
(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 Company–s 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.
(5) During the third quarter of 2013, the Company recorded an after-tax gain of $231 million related to the acquisition of Barrick Energy Inc. and the disposition of a 50% working interest in an exploration right in South Africa.
(6) All substantively enacted adjustments in applicable income tax rates and other legislative changes are applied to underlying assets and liabilities on the Company–s balance sheets in determining deferred income tax assets and liabilities. The impact of these tax rate and other legislative changes is recorded in net earnings during the period the legislation is substantively enacted. During the second quarter of 2013, the government of British Columbia substantively enacted legislation to increase its provincial corporate income tax rate effective April 1, 2013, resulting in an increase in the Company–s deferred income tax liability of $15 million.
Cash Flow from Operations
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
Net earnings for the nine months ended September 30, 2013 were $1,857 million compared with $1,540 million for the nine months ended September 30, 2012. Net earnings for the nine months ended September 30, 2013 included net after-tax expenses of $15 million compared with net after-tax income of $281 million for the nine months ended September 30, 2012 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates including the impact of a realized foreign exchange gain on repayment of long-term debt, the gain on corporate acquisition/disposition of properties, and the impact of statutory tax rate and other legislative changes on deferred income tax liabilities. Excluding these items, adjusted net earnings from operations for the nine months ended September 30, 2013 were $1,872 million compared with $1,259 million for the nine months ended September 30, 2012.
Net earnings for the third quarter of 2013 were $1,168 million compared with $360 million for the third quarter of 2012 and $476 million for the second quarter of 2013. Net earnings for the third quarter of 2013 included net after-tax income of $159 million compared with $7 million for the third quarter of 2012 and $14 million for the second quarter of 2013 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, the gain on corporate acquisition/disposition of properties, and the impact of statutory tax rate and other legislative changes on deferred income tax liabilities. Excluding these items, adjusted net earnings from operations for the third quarter of 2013 were $1,009 million compared with $353 million for the third quarter of 2012 and $462 million for the second quarter of 2013.
The increase in adjusted net earnings for the nine months ended September 30, 2013 from the comparable period in 2012 was primarily due to:
– higher crude oil and NGLs and synthetic crude oil (“SCO”) sales volumes in the North America and Oil Sands Mining and Upgrading segments;
– higher realized SCO prices;
– higher natural gas netbacks;
– higher realized risk management gains; and
– the impact of a weaker Canadian dollar;
partially offset by:
– lower natural gas sales volumes; and
– higher depletion, depreciation and amortization expense.
The increase in adjusted net earnings for the third quarter of 2013 from the comparable period in 2012 was primarily due to:
– higher crude oil and NGLs and SCO sales volumes in the North America and Oil Sands Mining and Upgrading segments;
– higher realized SCO prices;
– higher crude oil and NGLs netbacks;
– higher natural gas netbacks;
– lower realized risk management losses; and
– the impact of a weaker Canadian dollar;
partially offset by:
– lower natural gas sales volumes; and
– higher depletion, depreciation and amortization expense.
The increase in adjusted net earnings for the third quarter of 2013 from the second quarter of 2013 was primarily due to:
– higher crude oil and NGLs and SCO sales volumes in the North America and Oil Sands Mining and Upgrading segments;
– higher realized SCO prices;
– higher North America crude oil and NGLs netbacks; and
– the impact of a weaker Canadian dollar;
partially offset by:
– lower natural gas netbacks; and
– higher depletion, depreciation and amortization expense.
The impacts of share-based compensation, risk management activities and changes in foreign exchange rates are expected to continue to contribute to quarterly volatility in consolidated net earnings and are discussed in detail in the relevant sections of this MD&A.
Cash flow from operations for the nine months ended September 30, 2013 was $5,695 million compared with $4,465 million for the nine months ended September 30, 2012. Cash flow from operations for the third quarter of 2013 was $2,454 million compared with $1,431 million for the third quarter of 2012 and $1,670 million for the second quarter of 2013. The fluctuations in cash flow from operations from the comparable periods were 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 nine months ended September 30, 2013 increased 2% to 669,170 BOE/d from 653,220 BOE/d for the nine months ended September 30, 2012. Total production before royalties for the third quarter of 2013 increased 5% to 702,938 BOE/d from 667,616 BOE/d for the third quarter of 2012, and increased 13% from 623,315 BOE/d for the second quarter of 2013.
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 turnaround/suspension and subsequent 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 turnaround/suspension and subsequent 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 turnaround/suspension and subsequent 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.
– Gains on corporate acquisition/disposition of properties – Fluctuations due to the recognition of gains on corporate acquisitions/dispositions in the third quarter of 2013.
BUSINESS ENVIRONMENT
Commodity Prices
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$98.17 per bbl for the nine months ended September 30, 2013, an increase of 2% from US$96.20 per bbl for the nine months ended September 30, 2012. WTI averaged US$105.82 per bbl for the third quarter of 2013, an increase of 15% from US$92.19 per bbl for the third quarter of 2012, and an increase of 12% from US$94.23 per bbl for the second quarter of 2013.
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$108.40 per bbl for the nine months ended September 30, 2013, a decrease of 3% from US$112.07 per bbl for the nine months ended September 30, 2012. Brent averaged US$110.35 per bbl for the third quarter of 2013, an increase of 1% from US$109.57 per bbl for the third quarter of 2012, and an increase of 8% from US$102.44 per bbl for the second quarter of 2013.
WTI and Brent pricing were reflective of the political instability in the Middle East, creating volatility in the crude oil price. The Brent differential from WTI tightened for the three and nine months ended September 30, 2013 from the comparable periods due to a two-year low inventory level at Cushing of approximately 33 million barrels at September 30, 2013, reflecting a continued debottlenecking of logistical constraints from Cushing to the US Gulf Coast.
The WCS Heavy Differential averaged 23% for the nine months ended September 30, 2013 and was comparable with the nine months ended September 30, 2012. The WCS Heavy Differential averaged 16% for the third quarter of 2013 compared with 24% for the third quarter of 2012, and 20% for the second quarter of 2013. The WCS Heavy Differential tightened in the third quarter of 2013 from the comparable periods as a result of increased seasonal heavy oil demand as well as higher refinery utilization rates. The WCS Heavy Differential per barrel widened in October 2013 to average US$26.34 per bbl and in November 2013 to average US$31.31 per bbl. To partially mitigate its exposure to widening heavy crude oil differentials, as at September 30, 2013, the Company has entered into physical crude oil sales contracts with weighted average fixed WCS differentials as follows: 17,000 bbl/d in the fourth quarter of 2013 at US$21.49 per bbl; 8,000 bbl/d in the first quarter of 2014 at US$21.89 per bbl; 9,000 bbl/d in the second quarter of 2014 at US$21.93 per bbl; and 10,000 bbl/d in the third and fourth quarters of 2014 at US$20.81 per bbl.
The SCO price averaged US$101.49 per bbl for the nine months ended September 30, 2013, an increase of 9% from US$92.82 per bbl for the nine months ended September 30, 2012. The SCO price averaged US$109.97 per bbl for the third quarter of 2013, an increase of 21% from US$90.84 per bbl for the third quarter of 2012, and an increase of 11% from US$99.10 per bbl for the second quarter of 2013. The increase in SCO pricing for the three and nine months ended September 30, 2013 from the comparable periods was primarily due to the increase in benchmark pricing.
The Company uses condensate as a blending diluent for heavy crude oil pipeline shipments. During the third quarter of 2013, the condensate price differential from WTI narrowed, reflecting normal seasonality.
The Company anticipates continued volatility in crude oil pricing benchmarks due to supply and demand factors, geopolitical events, and the timing and extent of the 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$3.68 per MMBtu for the nine months ended September 30, 2013, an increase of 40% from US$2.62 per MMBtu for the nine months ended September 30, 2012. NYMEX natural gas prices averaged US$3.60 per MMBtu for the third quarter of 2013, an increase of 28% from US$2.82 per MMBtu for the third quarter of 2012, and a decrease of 12% from US$4.09 per MMBtu for the second quarter of 2013.
AECO natural gas prices for the nine months ended September 30, 2013 averaged $3.00 per GJ, an increase of 45% from $2.07 per GJ for the nine months ended September 30, 2012. AECO natural gas prices for the third quarter of 2013 averaged $2.68 per GJ, an increase of 29% from $2.08 per GJ for the third quarter of 2012, and a decrease of 21% from $3.41 per GJ for the second quarter of 2013.
During the third quarter of 2013, natural gas prices continued to recover from the low pricing levels in 2012. Natural gas prices increased for the three and nine months ended September 30, 2013 from the comparable periods in 2012 due to a return to normal natural gas storage levels. Natural gas prices decreased for the third quarter of 2013 from the second quarter of 2013 due to continued strong US supply and reduced weather related natural gas demand. AECO natural gas prices declined more than NYMEX in the third quarter due to changes in third party short-term tolling arrangements which resulted in higher costs to move natural gas to Eastern markets.
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 third quarter of 2013, the Company entered into a 20 year transportation agreement to ship 80,000 bbl/d of crude oil on the proposed Energy East pipeline originating at Hardisty, Alberta with delivery points in Quebec City, Quebec and Saint John, New Brunswick. This pipeline is subject to regulatory approval.
DAILY PRODUCTION, before royalties
(1) Net of blending costs and excluding risk management activities.
(2) Comparative figures have been adjusted to reflect realized product prices before transportation costs.
DAILY PRODUCTION, net of royalties
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 nine months ended September 30, 2013 increased 7% to 478,308 bbl/d from 445,140 bbl/d for the nine months ended September 30, 2012. Crude oil and NGLs production for the third quarter of 2013 increased 9% to 509,182 bbl/d from 469,168 bbl/d for the third quarter of 2012 and increased 17% from 436,363 bbl/d for the second quarter of 2013. The increase in production for the three and nine months ended September 30, 2013 from the comparable periods was primarily due to strong Horizon production, the impact of a strong heavy crude oil drilling program, and increased production from the Company–s cyclic thermal operations. Crude oil and NGLs production in the third quarter of 2013 was within the Company–s previously issued guidance of 506,000 to 529,000 bbl/d.
Natural gas production for the nine months ended September 30, 2013 decreased 8% to 1,145 MMcf/d from 1,248 MMcf/d for the nine months ended September 30, 2012. Natural gas production for the third quarter of 2013 decreased 2% to 1,163 MMcf/d from 1,191 MMcf/d for the third quarter of 2012 and increased 4% from 1,122 MMcf/d for the second quarter of 2013. The decrease in natural gas production for the three and nine months ended September 30, 2013 from the comparable periods in 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 for the third quarter of 2013 from the second qu