Canadian Natural Resources Limited Announces 2014 Fourth Quarter and Year End Results
(firmenpresse) - CALGARY, ALBERTA -- (Marketwired) -- 03/05/15 -- Commenting on fourth quarter and year end results, Steve Laut, President of Canadian Natural (TSX: CNQ)(NYSE: CNQ), stated, "2014 demonstrated the strength of our diverse and balanced asset base, and our ability to create long-term value for Canadian Natural's shareholders. At the end of the year, we increased Company Gross total proved plus probable reserves to 8.89 billion BOE, replacing 413% of production, with a proved plus probable reserve life index of approximately 31 years. Our annual average production volumes reached record levels and annual operating costs were optimized as compared to 2013 levels after successfully integrating the acquisition of higher cost production volumes in the first half of 2014.
Our transformation to a longer life, lower decline asset base remained on course as we delivered cost effective production volumes from Pelican Lake and brought Kirby South onstream. At Horizon Oil Sands, we commissioned the Phase 2A coker expansion ahead of schedule and below budget, resulting in increased utilization and name plate capacity. In 2015, we will leverage these execution synergies at Horizon, by reducing the scope of our planned 2015 turnaround, thereby increasing our 2015 annual Horizon production target by approximately 10,000 bbl/d. The majority of the original turnaround scope planned for 2015 will now be executed in May 2016 coincidental with additional Horizon project tie-in activity.
Although we were faced with new crude oil pricing challenges in the fourth quarter of 2014, we have been able to adapt quickly to the changing conditions through our nimble, flexible capital allocation. With a disciplined business approach and a focus on operating and capital costs, our proven strategy allows us to withstand the current commodity price challenges 2015 is bringing."
Canadian Natural's Chief Financial Officer, Corey Bieber, continued, "Strong cost management and prudent financial discipline continue to remain our focus given the volatility in commodity prices. Our proven track record of exercising capital flexibility and taking advantage of opportunities, such as the reduction in scope of the 2015 Horizon turnaround, facilitate the continued delivery of our defined plan and returning cash to shareholders, while maintaining a strong balance sheet and liquidity position. As a result of the Board of Directors' confidence in the Company's continued strength and successful execution of its proven and effective strategy, the quarterly cash dividend on common shares has once again been increased to $0.23 per share, the fifteenth straight year of increases in the Company's dividend. Available year end liquidity of $2.6 billion was subsequently bolstered in the first quarter of 2015 by the Company entering into a new $1.5 billion 3 year drawn bank credit facility, further supporting our financial stability and resilience. Beyond today's $150 million Horizon turnaround capital reduction, we retain additional optionality in our capital program as we move through 2015 and in future years, facilitating value creation for our shareholders irrespective of commodity price cycles."
QUARTERLY AND ANNUAL HIGHLIGHTS
Annual Overview
- Canadian Natural realized cash flow from operations in 2014 of approximately $9.6 billion. This is a 28% increase in cash flow compared to approximately $7.5 billion in 2013. The increase in cash flow was primarily due to higher overall crude oil and NGLs, natural gas and synthetic crude oil ("SCO") sales volumes in North America, higher crude oil and NGLs and natural gas netbacks in North America, higher realized risk management gains and the impact of a weaker Canadian dollar relative to the US dollar.
- Net earnings increased to $3.9 billion in 2014 compared to $2.3 billion in 2013. Adjusted net earnings from operations increased to $3.8 billion in 2014 compared to $2.4 billion in 2013. Changes in adjusted net earnings reflect the changes in cash flow from operations.
- Total overall production for the year averaged a record level of approximately 790,400 BOE/d, representing an increase of 18% from 2013 levels.
- Total crude oil and NGL production for the year averaged a record level of approximately 531,200 bbl/d, an increase of 11% from 2013 levels. Crude oil production was driven by the following:
-- 31% annual increase in North America light crude oil and NGL production as a result of the successful integration of production volumes acquired in the first half of 2014 and a successful drilling program,
-- 17% annual increase in Pelican Lake production due to excellent reservoir and polymer flood operating performance,
-- 12% annual increase in thermal in situ production as Kirby South volumes advanced toward 40,000 bbl/d,
-- 10% annual increase in Horizon Oil Sands Mining ("Horizon") production which included 25 days of planned downtime in Q3/14 used to complete the Coker plant expansion. Solid production volumes resulted from a continued focus on safe, steady and reliable operations targeting higher utilization rates; and,
-- 5% annual increase in primary heavy crude oil production as a result of a successful drilling program.
- Total natural gas production for the year averaged 1,555 MMcf/d and increased by 34% from 2013 levels due to the successful integration of volumes acquired in the first half of the year, the impact of full year production volumes from the Septimus expansion, and a concentrated liquids-rich natural gas drilling program.
- Canadian Natural ended 2014 with a strong balance sheet with debt to book capitalization of 33% and debt to EBITDA of 1.3x at December 31, 2014.
- Canadian Natural maintains significant financial stability and liquidity represented in part by bank credit facilities. As at December 31, 2014, the Company had in place bank credit facilities of $5,627 million, of which $2,643 million, net of commercial paper issuances of $580 million, was available.
- Subsequent to December 31, 2014, the Company entered into a new $1,500 million non-revolving term credit facility maturing April 2018. Additionally, the Company extended its existing $1,000 million non-revolving term credit facility to January 2017. The additional access to these credit facilities allows the Company to maintain its strong liquidity position.
- Canadian Natural has increased its quarterly cash dividend on common shares to C$0.23 per share from C$0.225 per share payable on April 1, 2015.
- Canadian Natural's crude oil, SCO, bitumen, natural gas and NGL reserves were evaluated and reviewed by Independent Qualified Reserves Evaluators. The following highlights are based on the Company's reserves using forecast prices and costs as at December 31, 2014 (all reserve values are Company Gross unless stated otherwise):
-- Canadian Natural total proved crude oil, SCO, bitumen and NGL reserves increased 2% to 4.51 billion barrels. Proved natural gas reserves increased 39% to 6.00 Tcf. Total proved reserves increased 7% to 5.51 billion BOE, resulting in a reserve life index of 19.0 years.
-- Canadian Natural total proved reserves increased by 662 million BOE through additions and revisions, resulting in a proved reserve replacement ratio of 230%.
-- Canadian Natural total proved plus probable crude oil, SCO, bitumen and NGL reserves increased 8% to 7.54 billion barrels. Proved plus probable natural gas reserves increased 33% to 8.14 Tcf. Total proved plus probable reserves increased 11% to 8.89 billion BOE resulting in a reserve life index of 30.6 years.
-- Canadian Natural total proved plus probable reserves increased by 1,188 million BOE through additions and revisions, resulting in a proved plus probable reserve replacement ratio of 413%.
-- Canadian Natural total net exploration and production reserve replacement expenditures totaled approximately $8.18 billion in 2014, including acquisitions and excluding Horizon. Horizon project capital (including capitalized interest, share-based compensation and other) totaled approximately $2.73 billion and sustaining and turnaround capital totaled approximately $380 million.
Fourth Quarter Overview
- Total crude oil and NGL production was approximately 572,000 bbl/d for Q4/14, an increase of 20% from Q4/13 levels, resulting largely from increased crude oil and NGL production volumes across all business divisions. Q4/14 production volumes increased by 10% from the previous quarter as a result of added production volumes from the successful completion of the coker expansion tie-in in Q3/14 at Horizon.
- Total natural gas production was 1,733 MMcf/d in Q4/14, an increase of 45% and 4% from Q4/13 and Q3/14 levels respectively. Increases in production levels, from the same quarter in the previous year, were largely due to acquisitions completed in the first half of the year and the concentrated liquids-rich Montney natural gas drilling program at Septimus. The increase from Q3/14 levels was primarily a result of minor property acquisitions completed in Q4/14 as well as growth from the current drilling program.
- Canadian Natural generated cash flow from operations of approximately $2.4 billion in Q4/14 compared to approximately $1.8 billion in Q4/13 and $2.4 billion in Q3/14. The increase in Q4/14 levels from Q4/13 levels reflect higher sales volumes in North America from crude oil and NGLs, natural gas and SCO, higher realized risk management gains and the impact of a weaker Canadian dollar relative to the US dollar partially offset by lower crude oil sales volumes in the Offshore Africa segment, lower crude oil and NGLs netbacks in the North America, North Sea and Offshore Africa segments and lower SCO prices. The slight reduction in cash flow from Q3/14 levels reflects lower crude oil and NGL netbacks in the North America, North Sea and Offshore Africa segments, lower realized SCO prices and lower crude oil sales volumes in Offshore Africa, partially offset by higher SCO sales volumes from Horizon, higher realized risk management gains and the impact of a weaker Canadian dollar as compared to the US dollar.
- Net earnings from operations for Q4/14 were $1,198 million, compared to net earnings of $413 million in Q4/13 and $1,039 million in Q3/14. Adjusted net earnings from operations for Q4/14 were $756 million, compared to adjusted net earnings of $563 million in Q4/13 and $984 million in Q3/14. Changes in adjusted net earnings reflect the changes in cash flow.
Operational and Financial Highlights
- In 2014 the Company achieved record annual aggregate production volumes for all North America Exploration and Production crude oil and NGL assets, which increased 14% from 2013 levels.
-- North America light crude oil and NGLs achieved record annual production volumes of approximately 89,600 bbl/d. Production increased 31% from 2013 levels, largely as a result of the successful integration of light crude oil and NGL production volumes acquired in the first half of 2014, as well as a successful drilling program.
-- Canadian Natural's primary heavy crude oil continued to provide strong netbacks and provides one of the highest returns on capital in the Company's portfolio of diverse and balanced assets. Primary heavy crude oil operations achieved record annual production of approximately 143,400 bbl/d, representing a 5% increase from 2013 levels.
-- Pelican Lake operations achieved record annual heavy crude oil production volumes of approximately 50,100 bbl/d, a 17% increase from 2013 levels. Canadian Natural continues to achieve success in developing, implementing and optimizing the leading edge polymer flood technology at Pelican Lake.
--- In Q4/14, Pelican Lake's operating costs were $7.82/bbl contributing to overall annual operating costs for 2014 of $8.52/bbl, representing a 20% decrease in operating costs from 2013 levels. Industry leading Pelican Lake operating costs drive high netbacks and significant free cash flow generation.
- During 2014 thermal in situ annual production volumes averaged approximately 107,800 bbl/d, a 12% increase from 2013 volumes primarily as a result of added volumes from Kirby South.
-- In September 2014, Canadian Natural received approval from the Alberta Energy Regulator ("AER") to implement a low pressure steamflood at Primrose East Area 1. The steamflood commenced and production is ramping up as expected.
-- Subsequent to December 31, 2014, the Company received approval from the AER to implement low pressure cyclic steam stimulation ("CSS") at Primrose East Area 2.
-- At Kirby South, Q4/14 production averaged approximately 22,200 bbl/d and production volumes continue to ramp up to the targeted 40,000 bbl/d of design capacity with the reservoir performing as expected.
- Horizon achieved record annual average production of approximately 110,600 bbl/d of SCO, an increase of 10% from 2013 levels. After successfully completing the Coker plant expansion in Q3/14, 8 months ahead of the original schedule, utilization rates at Horizon were 96% in Q4/14 as production volumes reached a quarterly record level of approximately 128,100 bbl/d of SCO.
-- Through the completion of Phase 2A, additional coker capacity and equipment were added, increasing the plant name plate capacity to 133,000 bbl/d. New equipment performance combined with an optimized mining strategy have increased the stability of the extraction and upgrading processes, resulting in a further increase to plant name plate capacity to 137,000 bbl/d. As a result, the last three months (December 2014, January 2015 and February 2015) production volumes were approximately 136,000 bbl/d, 135,600 bbl/d and 136,600 bbl/d respectively, at Horizon, representing a utilization level of 99%.
-- The addition of facility redundancy through the completion of Phase 2A, along with a more effective mining strategy, will place less maintenance stress on the downstream equipment and has increased overall performance of the plant. As a result of this increased performance and the strong execution of the Phase 2B expansion, the 35 day maintenance turnaround originally planned for the latter half of 2015 has been reduced in scope for this year to six days, and remaining work is now targeted for May 2016. In addition, due to continued strong construction performance on the Horizon expansion, the tie-in work for the Phase 2B expansion is now targeted to be completed during this 2016 maintenance turnaround, which will enable targeted production of Phase 2B to incrementally increase earlier than previously expected. Production volumes after the turnaround are targeted to increase by 4,000 bbl/d in Q3/16 and 10,000 bbl/d in Q4/16, above the original ramp up of production planned. Phase 2B is targeted to add 45,000 bbl/d of productive capacity once fully commissioned in late 2016.
-- The now planned 2015 six day turnaround is targeted for this fall to ensure continued safe, steady and reliable production at Horizon. As a result of a shorter planned 2015 turnaround period, additional production volumes of 10,000 bbl/d are now targeted for 2015 and annual production guidance has increased to 121,000 bbl/d to 131,000 bbl/d.
-- Adjusted operating costs at Horizon averaged $37.18/bbl in 2014, representing a decrease of 8% from levels of $40.57/bbl in 2013. In Q4/14, adjusted operating costs averaged $34.34/bbl, representing a decrease of 12% and 8% from Q4/13 and Q3/14 levels respectively. Decreases in adjusted operating costs reflect improvement in safe, steady and reliable operations, the impact of cost reduction initiatives across the site, the production and internal use of mine diesel, and higher production volumes on a relatively fixed cost structure. Due to these improvements at Horizon, adjusted cash production costs are targeted to further decrease in 2015 and average between $32.00/bbl to $35.00/bbl this year.
- Total natural gas production reached 1,555 MMcf/d on an annual basis in 2014, an increase of 34% from 2013 levels. The increase from 2013 levels resulted from the successful integration of acquired properties in North America, the impact of full year production volumes from the Septimus expansion, and a concentrated liquids-rich natural gas drilling program.
- Western Canadian Select ("WCS") differential to West Texas Intermediate ("WTI") averaged US$19.41/bbl or 21% in 2014 compared to US$25.11/bbl or 26% in 2013. A narrower differential resulted from additional heavy crude oil demand in the U.S. Midwest and increased takeaway capacity to the U.S. Gulf Coast.
- Canadian Natural is continuing its review of its royalty lands and royalty revenue portfolio and the best options to maximize shareholder value. Options for a final strategy as it relates to its fee title and royalty lands are as follows:
-- Divestiture of the portfolio assets,
-- Spin-off of the portfolio assets (IPO), or
-- Retention of the portfolio assets in their current state.
--- The development of leased acreage is ongoing and lease requests on undeveloped acreage continue to be evaluated. Production on the royalty lands has increased 10% from Q2/14 levels to Q3/14 levels. Drilling activity has been strong on the Company's royalty lands with 268 wells drilled in Q3/14 and Q4/14, of which 219 wells were drilled by third party and 49 wells were drilled by Canadian Natural.
- For the year ended December 31, 2014, the Company purchased for cancellation, under its Normal Course Issuer Bid, 10,095,000 common shares at a weighted average price of $44.85 per common share.
- Canadian Natural has increased its quarterly cash dividend on common shares to C$0.23 per share from C$0.225 per share payable on April 1, 2015.
2015 Capital and Operating Budget Updates
- Capital guidance for 2015 has been reduced by $150 million as a result of the reduction in scope of the originally planned 2015 Horizon maintenance turnaround from 35 days to 6 days. This is a result of the increased operating performance and the strong execution of the Phase 2B expansion. Tie-in work for the Phase 2B expansion will be completed during the maintenance turnaround, now targeted for May 2016.
- As a result of the focus on cost control in the current commodity price environment, members of Canadian Natural's Management Committee have agreed to a 10% salary reduction, effective March 1, 2015. Concurrently, the Board of Directors has also agreed to reduce their annual Board cash retainer by 10%.
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.
North America Exploration and Production
- North America crude oil and NGLs achieved record quarterly production of approximately 291,000 bbl/d in Q4/14, an increase of 14% from Q4/13 levels and a slight increase from Q3/14 levels.
- In Q4/14, primary heavy crude oil operations achieved record quarterly production of approximately 144,700 bbl/d. Primary heavy crude oil production increased 7% from Q4/13 levels and achieved a slight increase from Q3/14 levels. The Company's large undeveloped land base, effective and efficient drilling program and vast inventory of over 8,000 potential well locations enables Canadian Natural to remain the industry leading primary heavy crude oil producer. Canadian Natural continued with its large and cost efficient drilling program, drilling 896 net primary heavy crude oil wells in 2014.
- Canadian Natural's primary heavy crude oil assets provide strong netbacks and are amongst the highest return on capital in the Company's North America portfolio of diverse and balanced assets.
- Pelican Lake operations achieved record annual heavy crude oil production volumes of approximately 50,100 bbl/d, a 17% increase from 2013 levels. Canadian Natural continues to achieve success in developing, implementing and optimizing the leading edge polymer flood technology at Pelican Lake.
-- In Q4/14, Pelican Lake's operating costs were $7.82/bbl contributing to overall annual operating costs for 2014 of $8.52/bbl, representing a 20% decrease in operating costs from 2013 levels. Industry leading Pelican Lake operating costs drive high netbacks and significant free cash flow generation.
- North America light crude oil and NGLs achieved record quarterly production of approximately 95,600 bbl/d in Q4/14. Production increased 30% and 2% from Q4/13 levels and Q3/14 levels respectively, largely as a result of the successful integration of light crude oil and NGL production volumes acquired in 2014, as well as a successful drilling program.
- During 2014 thermal in situ annual production volumes averaged approximately 107,800 bbl/d, a 12% increase from 2013 volumes primarily as a result of added volumes from Kirby South.
- Q4/14 thermal in situ production volumes were approximately 119,000 bbl/d, representing an increase of 52% and 3% from Q4/13 and Q3/14 levels respectively. The increase in Q4/14 from Q4/13 levels primarily reflects the recommencement of steaming at Primrose East Area 1 and the addition of increased Kirby South production volumes.
- Primrose production volumes remained solid in Q4/14 as additional steaming approvals were received allowing execution of the Company's development plans:
-- In September 2014, Canadian Natural received approval from the AER to implement a low pressure steamflood at Primrose East Area 1. The steamflood commenced and production is ramping up as expected.
-- Primrose South received approval for additional CSS on four pads in September 2014; production is targeted to ramp up in 2015.
-- Subsequent to December 31, 2014, the Company received approval from the AER to implement low pressure CSS at Primrose East Area 2.
- At Kirby South, 2014 annual production averaged approximately 15,200 bbl/d as Q4/14 production volumes increased to an average of approximately 22,200 bbl/d. Kirby South continues to ramp to the targeted 40,000 bbl/d of design capacity with the reservoir performing as expected. Previously announced mechanical issues, which were resolved in Q3/14, limited the amount of steam entering the reservoir. The restriction in steam capacity deferred the timing to achieve full production capacity. Reservoir performance, as measured by steam to oil ratio ("SOR") continues to be strong with January 2015 and February 2015 SORs of 2.42 and 2.40 respectively for wells on Steam Assisted Gravity Drainage ("SAGD"), and total production levels of approximately 23,400 bbl/d and 25,300 bbl/d respectively.
- North America natural gas production averaged 1,705 MMcf/d for Q4/14, an increase of 46% and 4% from Q4/13 and Q3/14 levels respectively. The increase from Q4/13 levels resulted from additional production volumes acquired in the first half of the year and minor property acquisitions completed in Q4/14. The increase from Q3/14 levels was due to a concentrated liquids-rich natural gas drilling program and the successful integration of the previously mentioned acquired volumes.
- Concurrent with the successful integration of the acquired volumes and the continued focus on effective and efficient operations, the Company reduced operating costs related to these assets by approximately $86 million during 2014. Q4/14 operating costs were $1.34/Mcf, comparable to Q4/13 and Q3/14.
International Exploration and Production
- International crude oil production averaged approximately 34,000 bbl/d during Q4/14, comparable to Q4/13 levels and a 7% increase from Q3/14 levels. The increase in production over Q3/14 levels was primarily due to the reinstatement of the Banff/Kyle FPSO in July 2014. Production had been suspended for this FPSO since 2011 after the infrastructure suffered storm damage.
- Canadian Natural has contracted a drilling rig to undertake a 10 well (5.9 net) infill development drilling program targeted to add 5,900 BOE/d of net production at the Espoir field, offshore Cote d'Ivoire. Drilling commenced in January 2015 and first oil is targeted at the end of Q1/15.
- The Company has contracted a drilling rig to undertake a 6 well (3.5 net) infill development drilling program targeted to add 11,000 BOE/d of net production at the Baobab field, offshore Cote d'Ivoire. Drilling has commenced and first oil is targeted in Q2/15.
- In Q2/14, an exploratory well was drilled on Block CI-514, in which the Company has a 36% working interest. The well demonstrated the presence of a working petroleum system. A second well is targeted to be drilled in the first half of 2015 to evaluate the up-dip potential of the initial well.
- Canadian Natural has a 50% interest in the Block 11B/12B Exploration Right located in the Outeniqua Basin, approximately 175 kilometers off the southern coast of South Africa. In Q3/14, the operator, Total E&P South Africa BV, a wholly owned subsidiary of Total SA, commenced drilling the first exploratory well. In Q4/14, the exploration well was suspended due to mechanical issues with marine equipment on the drilling rig. The rig safely left the well location and, as the available drilling window has ended, it has been demobilized by the operator. The South African authorities have formally confirmed that the well drilled satisfies the work obligation for the initial period of the Block 11B/12B Exploration Right. The operator is reviewing the course of action to re-enter the well, and has indicated drilling operations are unlikely to resume in the area before 2016.
North America Oil Sands Mining and Upgrading - Horizon
- Horizon achieved record annual average production of approximately 110,600 bbl/d of SCO, an increase of 10% from 2013 levels. After successfully completing the Coker plant expansion in Q3/14, 8 months ahead of the original schedule, utilization rates at Horizon were 96% in Q4/14 as production volumes reached a quarterly record level of approximately 128,100 bbl/d of SCO.
- Through the completion of Phase 2A, additional coker capacity and equipment were added, increasing the plant name plate capacity to 133,000 bbl/d. New equipment performance combined with an optimized mining strategy have increased the stability of the extraction and upgrading processes, resulting in a further increase to plant name plate capacity to 137,000 bbl/d. As a result, the last three months (December 2014, January 2015 and February 2015) production volumes were approximately 136,000 bbl/d, 135,600 bbl/d and 136,600 bbl/d respectively, at Horizon, representing a utilization level of 99%.
- The addition of facility redundancy through the completion of Phase 2A, along with a more effective mining strategy, will place less maintenance stress on the downstream equipment and has increased overall performance of the plant. As a result of this increased performance and the strong execution of the Phase 2B expansion, the 35 day maintenance turnaround originally planned for the latter half of 2015 has been reduced in scope for this year to six days, and remaining work is now targeted for May 2016. In addition, due to continued strong construction performance on the Horizon expansion, the tie-in work for the Phase 2B expansion is now targeted to be completed during this 2016 maintenance turnaround, which will enable targeted production of Phase 2B to incrementally increase earlier than previously expected. Production volumes after the turnaround are targeted to increase by 4,000 bbl/d in Q3/16 and 10,000 bbl/d in Q4/16, above the original ramp up of production planned. Phase 2B is targeted to add 45,000 bbl/d of productive capacity once fully commissioned in late 2016.
- The now planned 2015 six day turnaround is targeted for this fall to ensure continued safe, steady and reliable production at Horizon. As a result of a shorter planned 2015 turnaround period, additional production volumes of 10,000 bbl/d are now targeted for 2015 and annual production guidance has increased to 121,000 bbl/d to 131,000 bbl/d.
- Adjusted operating costs at Horizon averaged $37.18/bbl in 2014, representing a decrease of 8% from levels of $40.57/bbl in 2013. In Q4/14, adjusted operating costs averaged $34.34/bbl, representing a decrease of 12% and 8% from Q4/13 and Q3/14 levels respectively. Decreases in adjusted operating costs reflect improvement in safe, steady and reliable operations, the impact of cost reduction initiatives across the site, the production and internal use of mine diesel, and higher production volumes on a relatively fixed cost structure. Due to these improvements at Horizon, adjusted cash production costs are targeted to further decrease in 2015 and average between $32.00/bbl to $35.00/bbl this year.
- Canadian Natural continues to deliver on its strategy to transition to a longer life, low decline asset base while providing significant and growing free cash flow. Canadian Natural's staged expansion of Horizon to 250,000 bbl/d of SCO production capacity continues to progress on track and within cost estimates. Canadian Natural has committed to approximately 72% of the Engineering, Procurement and Construction contracts with over 70% of the construction contracts awarded to date, 85% being lump sum, ensuring greater cost certainty and efficiency.
- Overall Horizon Phase 2/3 expansion is 56% physically complete as at Q4/14:
-- Reliability - Tranche 2 is 100% physically complete. Completion occurred in 2014 resulting in increased performance and overall production reliability. This phase contributed approximately 5% increase in production levels from Phase 1 production levels.
-- Directive 74 includes technological investment and research into tailings management. This project remains on track and is 51% physically complete.
-- Phase 2A is a coker expansion that 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 accelerated the tie-in to August 2014. The expanded Coker Unit is now fully operational and the project was completed on time and below budget. Horizon SCO production levels increased by approximately 12,000 bbl/d with the completion of the coker tie-in.
-- Phase 2B is 49% physically complete. This phase expands the capacity of major components such as gas/oil hydrotreatment, froth treatment and the hydrogen plant. As a result of strong project execution, certain components of this project will be tied-in during the May 2016 turnaround. Full commissioning of the Phase 2B equipment will be completed as planned in late 2016, adding 45,000 bbl/d of production capacity.
--Phase 3 is on track and on schedule. This phase is 44% physically complete, and includes the addition of extraction trains. This phase is targeted to increase production capacity by 80,000 bbl/d in late 2017 and will result in additional reliability, redundancy and significant operating cost savings for the Horizon project.
ROYALTIES
Based on the analysis completed to date, Canadian Natural reports the following information for quarterly royalty volumes, which are based on the Company's current estimate of revenue and volumes attributable to Q3/14:
Royalty Production Volumes Comparison (1)
Royalty Production Volumes (1)
Royalty Revenue by Product (1)
Revenue by Royalty Classification (1)
Royalty Realized Pricing (1)
Royalty Acreage
- The development of leased acreage is ongoing and lease requests on undeveloped acreage continue to be evaluated. Production on the royalty lands has increased 10% from Q2/14 levels to Q3/14 levels. Drilling activity has been strong on the Company's royalty lands with 268 wells drilled in Q3/14 and Q4/14, of which 219 wells were drilled by third party and 49 wells were drilled by Canadian Natural.
- The Company continues to focus on lease compliance, well commitments, offset drilling obligations and compensatory royalties payable.
- Royalty production volumes highlighted above are not reported in Canadian Natural's quarterly production volumes. Third party royalty revenues are included in reported Product Sales in the Company's consolidated statement of earnings.
MARKETING
- Volatility in supply and demand factors and geopolitical events continued to affect WTI and Brent pricing. During Q4/14, an oversupply in the world market contributed to a significant decrease in crude oil benchmark pricing. The Organization of the Petroleum Exporting Countries' ("OPEC") decision in November 2014 to not reduce crude oil production to offset the excess world supply continues to put downward pressure on benchmark pricing. The Brent differential from WTI narrowed during the fourth quarter of 2014 compared to the fourth quarter of 2013 due to continued debottlenecking of logistical constraints from Cushing to the US Gulf Coast in the first half of 2014.
- The WCS differential to WTI averaged US$19.41/bbl or 21% in 2014 compared to US$25.11/bbl or 26% in 2013. A narrower differential resulted from additional heavy crude oil demand in the U.S. Midwest and increased takeaway capacity to the U.S. Gulf Coast. Throughout 2015, seasonal demand fluctuations, changes in transportation logistics, and refinery utilization and shutdowns are expected to contribute to fluctuation in the WCS heavy oil differential.
- Canadian Natural contributed approximately 167,000 bbl/d of its heavy crude oil stream to the WCS blend in 2014. The Company remains the largest contributor to the WCS blend, accounting for 56% of the total blend in Q4/14.
- SCO pricing during Q4/14 decreased 20% and 25% from Q4/13 levels and Q3/14 levels respectively, primarily due to a decrease in benchmark pricing.
- During Q4/14, natural gas prices increased from Q4/13 due to the drawdown of natural gas storage inventories as a result of colder than normal winter temperatures in 2014. Natural gas prices decreased in Q4/14 from Q3/14 due to the strong growth in US natural gas production. The growth of US natural gas production resulted in inventories returning to normal industry levels at the end of 2014, leading to downward pressure on natural gas prices.
NORTH WEST REDWATER UPGRADING AND REFINING
The North West Redwater refinery, upon completion, 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. The Company has a 50% interest in the North West Redwater Partnership. For project updates, please refer to: .
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, US commercial paper program, diverse asset base and related flexible 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 approximately 790,400 BOE/d for 2014 with approximately 98% of production located in G8 countries.
- Canadian Natural has a strong balance sheet with debt to book capitalization of 33% and debt to EBITDA of 1.3x at December 31, 2014.
- Canadian Natural maintains significant financial stability and liquidity represented in part by bank credit facilities. As at December 31, 2014, the Company had in place bank credit facilities of $5,627 million, of which $2,643 million, net of commercial paper issuances of $580 million, was available.
- Subsequent to December 31, 2014, the Company entered into a new $1,500 million non-revolving term credit facility maturing April 2018. Additionally, the Company extended its existing $1,000 million non-revolving term credit facility to January 2017. The additional access to these credit facilities allows the Company to maintain its strong liquidity position.
- On November 12, 2014, Canadian Natural priced US$600 million principal amount of 1.75% unsecured notes due January 15, 2018 sold at a price of 99.921% per note to yield 1.776% to maturity, and US$600 million principal amount of 3.90% unsecured notes due February 1, 2025 sold at a price of 99.871% per note to yield 3.916% to maturity.
- The Company's commodity hedging program is utilized, as required, to protect investment returns, support ongoing balance sheet strength and the cash flow for its capital expenditure programs. Details of the Company's commodity hedging program can be found on the Company's website at .
- For the year ended December 31, 2014, the Company purchased for cancellation 10,095,000 common shares at a weighted average price of $44.85 per common share.
- Canadian Natural has increased its quarterly cash dividend on common shares to C$0.23 per share from C$0.225 per share payable on April 1, 2015.
- The Company has a strong balance sheet and cash flow generation which enables it to weather volatility in commodity prices. Additionally, Canadian Natural retains significant capital expenditure program flexibility to proactively adapt to changing market conditions.
OUTLOOK
The Company forecasts 2015 production levels before royalties to average between 562,000 and 602,000 bbl/d of crude oil and NGLs and between 1,730 and 1,770 MMcf/d of natural gas. Detailed guidance on production levels, capital allocation and operating costs can be found on the Company's website at .
YEAR-END RESERVES
Determination of Reserves
For the year ended December 31, 2014 the Company retained Independent Qualified Reserves Evaluators, Sproule Associates Limited, Sproule International Limited and GLJ Petroleum Consultants Ltd., to evaluate and review all of the Company's proved and proved plus probable reserves. Sproule evaluated the Company's North America and International crude oil, bitumen, natural gas and NGL reserves. GLJ evaluated the Company's Horizon synthetic crude oil reserves. The Evaluators conducted the evaluation and review in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). The reserves disclosure is presented in accordance with NI 51-101 requirements using forecast prices and escalated costs.
The Reserves Committee of the Company's Board of Directors has met with and carried out independent due diligence procedures with the Evaluators as to the Company's reserves. All reserve values are Company Gross unless stated otherwise.
Corporate Total
- Proved crude oil, SCO, bitumen and NGL reserves increased 2% to 4.51 billion barrels. Proved natural gas reserves increased 39% to 6.00 Tcf. Total proved reserves increased 7% to 5.51 billion BOE.
- Proved plus probable crude oil, SCO, bitumen and NGL reserves increased 8% to 7.54 billion barrels. Proved plus probable natural gas reserves increased 33% to 8.14 Tcf. Total proved plus probable reserves increased 11% to 8.89 billion BOE.
- Proved reserve additions and revisions, including acquisitions, were 282 million barrels of crude oil, SCO, bitumen and NGL and 2,264 billion cubic feet of natural gas. The total proved BOE reserve replacement ratio was 230%. The total proved BOE reserve life index is 19.0 years.
- Proved plus probable reserve additions and revisions, including acquisitions, were 753 million barrels of crude oil, bitumen, SCO and NGL and 2,597 billion cubic feet of natural gas. The total proved plus probable BOE reserve replacement ratio was 413%. The total proved plus probable BOE reserve life index is 30.6 years.
- Proved undeveloped crude oil, SCO, bitumen and NGL reserves accounted for 27% of the corporate total proved reserves and proved undeveloped natural gas reserves accounted for 5% of the corporate total proved reserves.
North America Exploration and Production
- Proved crude oil, bitumen and NGL reserves increased 9% to 2.05 billion barrels. Proved natural gas reserves increased 41% to 5.87 Tcf. Total proved BOE increased 18% to 3.03 billion barrels.
- Proved plus probable crude oil, bitumen and NGL reserves increased 9% to 3.49 billion barrels. Proved plus probable natural gas reserves increased 35% to 7.93 Tcf. Total proved plus probable BOE increased 15% to 4.81 billion barrels.
- Proved reserve additions and revisions, including acquisitions, were 308 million barrels of crude oil, bitumen and NGL and 2,266 billion cubic feet of natural gas. The total proved BOE reserve replacement ratio is 292%. The total proved BOE reserve life index in 13.1 years.
- Proved plus probable reserve additions and revisions, including acquisitions, were 420 million barrels of crude oil, bitumen and NGL and 2,602 billion cubic feet of natural gas. The total proved plus probable BOE reserve replacement ratio was 363%. The total proved plus probable BOE reserve life index is 20.7 years.
- Proved undeveloped crude oil, bitumen and NGL reserves accounted for 36% of the North America total proved reserves and proved undeveloped natural gas reserves accounted for 9% of the North America total proved reserves.
- Thermal oil sands ("bitumen") proved reserves increased 5% to 1.22 billion barrels primarily due new proved undeveloped additions at Primrose and Wolf Lake. Proved reserve additions and revisions were 99 million barrels. Total proved plus probable bitumen reserves increased 7% to 2.31 billion barrels.
North America Oil Sands Mining and Upgrading
- Proved plus probable SCO reserves increased 9% to 3.59 billion barrels, primarily due to a revised mine plan allowing mining to Total Volume : Bitumen In Place ("TV:BIP") of 13 versus 12 in the original plan.
International Exploration and Production
- North Sea proved reserves decreased 9% to 218 million BOE. North Sea proved plus probable reserves decreased 5% to 327 million BOE.
- Offshore Africa proved reserves decreased 4% to 104 million BOE primarily due to production. Offshore Africa proved plus probable reserves decreased 3% to 165 million BOE.
Reserves Notes:
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, the construction and future operations of the North West Redwater bitumen upgrader and refinery, and construction by third parties of new or expansion of existing pipeline capacity or other means of transportation of bitumen, crude oil, natural gas or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market 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 and year ended December 31, 2014 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2013.
All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's unaudited interim consolidated financial statements for the period ended December 31, 2014 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 adjusted 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 adjusted 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 SCO.
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 and analysis refers primarily to the Company's financial results for the three months and year ended December 31, 2014 in relation to the comparable periods in 2013 and the third quarter of 2014. 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, 2013, is available on SEDAR at , and on EDGAR at . This MD&A is dated March 4, 2015.
FINANCIAL HIGHLIGHTS
Adjusted Net Earnings from Operations
Cash Flow from Operations
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
Net earnings for the year ended December 31, 2014 were $3,929 million compared with $2,270 million for the year ended December 31, 2013. Net earnings for the year ended December 31, 2014 included net after-tax income of $118 million compared with net after-tax expenses of $165 million for the year ended December 31, 2013 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates including the impact of realized foreign exchange losses and gains on repayments of long-term debt, gains on corporate acquisitions/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 year ended December 31, 2014 were $3,811 million compared with $2,435 million for the year ended December 31, 2013.
Net earnings for the fourth quarter of 2014 were $1,198 million compared with $413 million for the fourth quarter of 2013 and $1,039 million for the third quarter of 2014. Net earnings for the fourth quarter of 2014 included net after-tax income of $442 million compared with net after-tax expenses of $150 million for the fourth quarter of 2013 and net after-tax income of $55 million for the third quarter of 2014 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates including the impact of a realized foreign exchange loss on repayment of long-term debt, and the gain on corporate acquisitions/disposition of properties. Excluding these items, adjusted net earnings from operations for the fourth quarter of 2014 were $756 million compared with $563 million for the fourth quarter of 2013 and $984 million for the third quarter of 2014.
The increase in adjusted net earnings for the year ended December 31, 2014 from the comparable period in 2013 was primarily due to:
- higher crude oil and NGLs, natural gas, and SCO sales volumes in the North America and Oil Sands Mining and Upgrading segments;
- higher crude oil and NGLs and natural gas netbacks in the North America segment;
- higher realized risk management gains; and
- the impact of a weaker Canadian dollar relative to the US dollar;
partially offset by:
- lower crude oil sales volumes in the Offshore Africa segment; and
- lower crude oil netbacks in the North Sea and Offshore Africa segments.
The increase in adjusted net earnings for the fourth quarter of 2014 from the fourth quarter of 2013 was primarily due to:
- higher crude oil and NGLs, natural gas, and SCO sales volumes in the North America, Oil Sands Mining and Upgrading and North Sea segments;
- higher realized risk management gains; and
- the impact of a weaker Canadian dollar relative to the US dollar;
partially offset by:
- lower crude oil and NGLs netbacks in the North America and North Sea segment;
- lower crude oil sales volumes in the Offshore Africa segment; and
- lower realized SCO prices.
The decrease in adjusted net earnings for the fourth quarter of 2014 from the third quarter of 2014 was primarily due to:
- lower crude oil and NGLs netbacks in the North America, North Sea and Offshore Africa segments;
- lower realized SCO prices; and
- lower crude oil sales volumes in the Offshore Africa segment;
partially offset by:
- higher SCO and crude oil and NGLs sales volumes in the Oil Sands Mining and Upgrading and North Sea segment;
- higher realized risk management gains; and
- the impact of a weaker Canadian dollar relative to the US dollar.
The impacts of share-based compensation, risk management activities and fluctuations 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 year ended December 31, 2014 was $9,587 million compared with $7,477 million for the year ended December 31, 2013. Cash flow from operations for the fourth quarter of 2014 was $2,368 million compared with $1,782 million for the fourth quarter of 2013 and $2,440 million for the third quarter of 2014. 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, together with the impact of lower cash taxes.
Total production before royalties for the year ended December 31, 2014 increased 18% to 790,410 BOE/d from 671,162 BOE/d for the year ended December 31, 2013. Total production before royalties for the fourth quarter of 2014 increased 27% to 860,920 BOE/d from 677,242 BOE/d for the fourth quarter of 2013 and increased 8% from 796,931 BOE/d for the third quarter of 2014.
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, increased shale oil production in North America, the impact of geopolitical uncertainties on worldwide benchmark pricing, the impact of the WCS Heavy Differential from the 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, production from Kirby South, the results from the Pelican Lake water and polymer flood projects, the strong heavy crude oil drilling program, the impact and timing of acquisitions, and the impact of turnarounds 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 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 and production, the impact of seasonal costs that are dependent on weather, cost optimizations in North America, the impact and timing of acquisitions, and turnarounds at Horizon.
- Depletion, depreciation and amortization - Fluctuations due to changes in sales volumes including the impact and timing of acquisitions, 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, fluctuations in depletion, depreciation and amortization expense in the North Sea resulting from the planned early cessation of production at the Murchison platform, and the impact of turnarounds 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, which 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 acquisitions/disposition of properties - Fluctuations due to the recognition of gains on corporate acquisitions/dispositions in the fourth quarter of 2014 and the third quarter of 2013.
BUSINESS ENVIRONMENT
Substantially all of the Company's production is sold based on US dollar benchmark pricing. Specifically, crude oil is marketed based on WTI and Brent indices. Canadian natural gas pricing is primarily based on Alberta AECO reference pricing, which is derived from the NYMEX reference pricing and adjusted for its basis or location differential to the NYMEX delivery point at H
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Datum: 05.03.2015 - 10:00 Uhr
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