CALGARY, ALBERTA — (Marketwire) — 03/07/13 — Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ)
Commenting on fourth quarter and year end results, Canadian Natural–s Vice-Chairman, John Langille stated, “Canadian Natural generated in 2012 over $6.0 billion of annual cash flow from operations and demonstrated capital discipline throughout the year. The Company–s exhibited long term ability to maintain flexibility of capital allocation and financial discipline over different commodity price cycles has helped us weather challenging conditions and capitalize when opportunities arise. Prudent management of our balance sheet resulted in year-end debt to book capitalization of 26% and year-end debt to EBITDA of 1.2 times.
As part of the Company–s long term goal to return funds to its shareholders, throughout 2012, the Company purchased for cancellation under its Normal Course Issuer Bid over eleven million common shares at an average price of $28.91. For 2013, the Board has approved a 19% dividend increase to C$0.125 per quarter, C$0.50 per share annualized. This will be the thirteenth consecutive year that the Company has announced an increased annual dividend distribution representing a compound annual growth rate of 21% over the period. In addition, the Company–s Board of Directors have directed Management to continue with an active program, subject to market conditions, to purchase for cancellation common shares under the Company–s Normal Course Issuer Bid at or above the levels of shares purchased in financial year 2012. Our share purchase program and dividend increases, along with the defined resource development of our diverse asset base, and our debt management and opportunistic acquisitions demonstrate our balanced approach to our long standing effective strategy. Canadian Natural is strong and stable, and well positioned to deliver shareholder value in the near, mid and long term.”
Steve Laut, President of Canadian Natural concluded, “During 2012, the Company made very good progress in our transition to a longer life, low decline asset base. We continued to balance development of our large resource base by focusing on high return assets and our ability to deliver timely results. In 2012 we made significant progress towards continued execution on the creation of shareholder value. We achieved 9% overall production growth in 2012 from 2011. At Horizon, substantial improvements have been made in operating discipline and our enhanced concentration on safe, steady and reliable operations has led to greater plant reliability. At Kirby, construction progress has been solid and we are 81% complete and on budget. We had another solid year of adding new reserves. Our barrel of oil equivalent reserves on a Company Gross proved plus probable basis increased by 5% to 7.9 billion barrels, replacing 246% of our 2012 production.
For 2013 and beyond, we will continue to focus on operating efficiencies and discipline and will allocate capital to projects that provide the greatest value and highest returns to our shareholders. This will allow the Company over time to generate strong and growing free cash flow.”
QUARTERLY AND ANNUAL 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.
Fourth Quarter
– Total crude oil and NGLs production was 469,964 bbl/d for Q4/12. Q4/12 crude oil production volumes increased 6% from Q4/11 as a result of a strong thermal in situ production cycle and successful primary heavy and light crude oil drilling programs.
– Total natural gas production for Q4/12 was 1,134 MMcf/d. Q4/12 natural gas production volumes decreased 11% and 5%, as expected, from Q4/11 and Q3/12 respectively. The decrease in production was primarily due to expected production declines and shut in production volumes as a result of the Company–s strategic decision to allocate capital to higher return crude oil projects.
– Canadian Natural generated quarterly cash flow from operations of $1.55 billion compared with $2.16 billion in Q4/11 and $1.43 billion in Q3/12. The decrease in cash flow from Q4/11 was due to lower average realized product prices, lower natural gas sales volumes, and lower synthetic crude oil (“SCO”) sales volumes. These factors were partially offset by higher crude oil sales volumes in North America. The increase in cash flow from Q3/12 was primarily related to higher North America crude oil and NGLs sales volumes.
– Adjusted net earnings from operations for Q4/12 was $359 million, compared to adjusted net earnings of $972 million in Q4/11 and $353 million in Q3/12. Changes in adjusted net earnings reflect the changes in cash flow from operations.
Annual
– Total overall production for the year averaged 654,665 BOE/d representing an increase of 9% from 2011. Canadian Natural–s production volume growth was driven by successful light and heavy crude oil drilling programs and greater reliability of Horizon Oil Sands (“Horizon”) operations.
– Total crude oil and NGLs production for the year averaged 451,378 bbl/d, an increase of 16% from 2011. The Company–s strategic allocation of capital to crude oil projects resulted in a 22% annual increase in primary heavy crude oil production volumes, a 13% annual increase of North America light crude oil and NGLs production and a 113% annual increase in Horizon production.
– As expected, total natural gas production for the year averaged 1,220 MMcf/d, a decrease of 3% from 2011 levels. The decrease in production was due to expected production declines, shut in production volumes and a reduced drilling program, reflecting Canadian Natural–s strategic decision to allocate capital to higher return crude oil projects.
– Cash flow from operations was approximately $6.0 billion in 2012 compared to approximately $6.5 billion in 2011. The decrease in cash flow was primarily due to lower realized crude oil and NGLs prices, lower realized natural gas prices and lower realized SCO prices. These factors were partially offset by higher crude oil and SCO production volumes in North America.
– Adjusted net earnings from operations in 2012 decreased to $1.6 billion compared to $2.5 billion in 2011. Changes in adjusted net earnings reflect the changes in cash flow from operations and higher depletion, depreciation and amortization (“DD&A”) expense.
– Canadian Natural–s crude oil and natural gas reserves were reviewed and evaluated by independent qualified reserves evaluators. The following are highlights based on the Company Gross reserves using forecast prices and costs as at December 31, 2012:
— Company Gross proved crude oil, SCO, bitumen and NGL reserves increased 6% to 4.33 billion barrels. Company Gross proved natural gas reserves decreased 7% to 4.14 Tcf. On a BOE basis total proved reserves increased 4% to 5.02 billion BOE.
— Company Gross proved plus probable crude oil, SCO, bitumen and NGL reserves increased 6% to 6.92 billion barrels. Company Gross proved plus probable natural gas reserves decreased 5% to 5.79 Tcf. On a BOE basis total proved plus probable reserves increased 5% to 7.89 billion BOE.
— Company Gross proved reserve additions, including acquisitions, were 404 million barrels of crude oil, SCO, bitumen and NGL and 135 billion cubic feet of natural gas for 426 million BOE. The total proved reserve replacement ratio was 178%. The total proved reserve life index is 22.8 years.
— Company Gross proved plus probable reserve additions, including acquisitions, were 565 million barrels of crude oil, bitumen, SCO and NGL and 132 billion cubic feet of natural gas for 587 million BOE. The total proved plus probable reserve replacement ratio was 246%. The total proved plus probable reserve life index is 35.8 years.
— Proved undeveloped crude oil, SCO, bitumen and NGL reserves accounted for 31% of the corporate total proved reserves and proved undeveloped natural gas reserves accounted for 4% of the corporate total proved reserves.
— Of the reserve additions by the Company in 2012, 95% of Company Gross proved reserve additions and 96% of Company Gross proved plus probable reserve additions were crude oil, SCO, bitumen and NGLs.
– Total net exploration and production reserve replacement expenditures totaled approximately $4,444 million in 2012, including acquisitions and excluding Horizon. Horizon project capital (including capitalized interest, share-based compensation and other) totaled approximately $1,366 million and sustaining and turnaround capital totaled approximately $244 million.
Operational and Financial
– North America Exploration and Production crude oil and NGLs production for the year averaged 326,829 bbl/d representing an increase of 11% from 2011 levels.
— Canadian Natural–s primary heavy crude oil continued to provide strong netbacks and the highest return on capital in the Company–s portfolio of diverse and balanced assets. Primary heavy crude oil operations achieved Q4/12 production volumes of over 130,000 bbl/d, resulting in the eighth consecutive quarter of record production which contributed to 22% average annual production growth over 2011. Primary heavy crude oil production volumes are targeted to increase by a further 13% in 2013.
— Completion of another successful light crude oil drilling program of 124 net wells, Enhanced Oil Recovery (“EOR”) activities and acquisitions resulted in 13% annual growth of North America light crude oil and NGLs production volumes over 2011 levels. North America light crude oil and NGLs production volumes in 2013 are targeted to increase by 6%.
— Pelican Lake reservoir performance throughout 2012 was very positive. In Q4/12, production averaged approximately 36,400 bbl/d as volumes at Pelican Lake were restricted due to temporary produced polymer treatment and facility constraints. In addition, production volumes from the primary heavy oil area of Woodenhouse were also restricted as they utilize Pelican Lake processing facilities. Construction completion of a new battery targeted in June 2013 will correct the temporary treatment constraints and enable a step increase in Pelican Lake and Woodenhouse production volumes through the second half of 2013. Annual production guidance for Pelican Lake remains unchanged and is targeted to range from 46,000 bbl/d to 50,000 bbl/d.
— Thermal in situ production ramped up during 2012 as pads re-entered the production cycle. Q4/12 volumes averaged 121,000 bbl/d, a 19% increase over Q3/12 volumes. 2012 annual thermal production averaged approximately 99,500 bbl/d and is targeted to grow by 5% in 2013.
— In 2012, Canadian Natural acquired an additional 12,630 net hectares of leases at its Kirby Thermal Oil Sands Project (“Kirby Project”), which are being incorporated into the Company–s robust portfolio of thermal in situ projects. The Company–s thermal projects are targeted to add 40,000 bbl/d of production every two to three years that is targeted to ultimately grow to approximately 500,000 bbl/d of capacity, from current production capacity of 130,000 bbl/d. The Company Gross proved plus probable long-life, low-decline bitumen reserves from thermal in situ oil sands increased by 23%, to 2,122 million barrels in 2012 and total Company Gross proved bitumen reserves increased by 9%, to 1,066 million barrels in 2012.
— Kirby South Phase 1, the Company–s first large scale steam assisted gravity drainage (“SAGD”) project, is targeted for first steam in Q4/13 and is targeted to add 40,000 bbl/d of production in late 2014. Construction is progressing slightly ahead of schedule and on budget.
– Horizon SCO production volumes averaged approximately 86,000 bbl/d in 2012. The Company continues its enhanced focus on operational discipline and safe, steady and reliable operations at Horizon. Reliability of the Horizon plant continues to steadily improve and annual SCO production is targeted to range from 100,000 bbl/d to 108,000 bbl/d in 2013, which includes the impact of the planned May 2013 turnaround.
— The addition of the third ore preparation plant (“OPP”) and associated hydro-transport unit was integrated into the Company–s mining operations in early 2012. The equipment has substantially increased the overall reliability at Horizon.
— In January and February 2013, strong performance from Horizon resulted in average SCO volumes of approximately 113,000 bbl/d and 107,000 bbl/d, respectively. Q1/13 production guidance is targeted to range from 105,000 bbl/d to 111,000 bbl/d of SCO.
— Canadian Natural maintains a flexible schedule for Horizon expansion construction to ensure capital efficiencies. The staged expansion to 250,000 bbl/d of SCO production capacity at Horizon continues to be broken down into smaller more focused projects which has kept projects currently under construction trending at or below cost estimates. In 2012, long life, low decline SCO Company Gross proved reserves increased 6% to 2.26 billion barrels. SCO Company Gross proved plus probable reserves remained essentially unchanged at 3.35 billion barrels.
– During Q4/12, the Redwater Partnership 50,000 bbl/d bitumen refinery (78,000 bbl/d of bitumen blend) was sanctioned by its owners (50% Canadian Natural). The Company will provide 12,500 bbl/d of bitumen feedstock to the refinery as a toll payer. Work continues on the Redwater project and completion is targeted for mid-2016.
– During 2012, Canadian Natural purchased 11,012,700 common shares for cancellation at a weighted average price of $28.91 per common share.
– For 2013, the Board has approved a 19% dividend increase to C$0.125 per quarter, C$0.50 per share annualized. This will be the thirteenth consecutive year that the Company has announced an increased annual dividend distribution representing a compound annual growth rate of 21% over the period.
– In addition, the Company–s Board of Directors have directed Management to continue with an active program, subject to market conditions, to purchase for cancellation common shares under the Company–s Normal Course Issuer Bid at or above the levels of shares purchased in financial year 2012.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural focuses its activities in core regions where it can own a substantial land base and associated infrastructure. Land inventories are maintained to enable continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By owning and operating associated infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production costs. Further, the Company maintains large project inventories and production diversification among each of the commodities it produces; light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen and SCO (herein collectively referred to as “crude oil”), natural gas and NGLs. A large diversified project portfolio enables the effective allocation of capital to higher return opportunities.
OPERATIONS REVIEW
(1) Unproved land refers to a property or part of a property to which no reserves have been specifically attributed.
(2) Drilling activity includes stratigraphic test and service wells.
North America Exploration and Production
– North America crude oil and NGLs production for the year averaged 326,829 bbl/d representing an increase of 11% from 2011. The increase in average yearly production was largely a result of successful drilling programs in primary heavy and light crude oil.
– North America crude oil and NGLs production for Q4/12 was 351,983 bbl/d. Q4/12 crude oil and NGLs production volumes increased 21% and 6% from Q4/11 and Q3/12 levels, respectively. The increase in production from Q4/11 was driven by higher primary heavy crude oil and thermal production volumes.
– Primary heavy crude oil operations achieved record quarterly production in Q4/12 of approximately 130,200 bbl/d which contributed to 22% average annual production growth over 2011 levels. Canadian Natural executed a record drilling program of 886 net primary heavy crude oil wells in 2012.
– During 2012 the reservoir performance at Pelican Lake demonstrated expected positive results.
— Strong operating efficiencies were achieved at Pelican Lake as operating costs decreased to an annual average of $11.89/bbl in 2012.
— In Q4/12, reservoir performance remained strong with incremental production response from the polymer flood. As production increased to facility capacity, the ability to treat the polymer produced was constrained. As a result, oil production at both Pelican Lake and Woodenhouse was curtailed.
— Construction of the new battery, targeted for completion in June 2013, will address these temporary treatment constraints and enable a step increase in production volumes at both Pelican Lake and Woodenhouse. 2013 production expected for Pelican Lake remains unchanged and is targeted to range from 46,000 bbl/d to 50,000 bbl/d.
– North America light crude oil and NGLs annual production increased 13% in 2012 over 2011 levels as a result of a successful drilling program consisting of 124 net light crude oil wells. In 2013, Canadian Natural targets to drill 114 net light crude oil wells, 41 of which are targeting new play developments that were initiated in 2012. The Company continues to advance horizontal multi-frac well technology in pools across its land base. In addition, 70% of targeted total drilling will be focused on horizontal wells.
– Canadian Natural–s robust portfolio of thermal in situ projects is a significant part of the Company–s defined plan to transition to a longer-life, more sustainable asset base with the ability to generate significant shareholder value for decades to come. The Company targets to grow thermal in situ production to approximately 500,000 bbl/d of capacity by delivering projects that will add 40,000 bbl/d of production every two to three years.
— At Primrose, total thermal operating costs including energy costs for Q4/12 were $7.95/bbl. Annual thermal operating costs including energy costs were $9.69/bbl. Thermal production averaged over 120,000 bbl/d in Q4/12, representing a 19% increase from Q3/12 to Q4/12, primarily due to new pads at Primrose East entering their production cycles. Production volumes are targeted to increase by 5% in 2013.
— Kirby South Phase 1 is slightly ahead of plan and on budget. All major equipment and modules have been delivered and installed on site with overall construction progress ahead of schedule. An update to the project at the end of Q4/12 is as follows:
— Overall project is 81% complete.
— Overall construction is 73% complete.
— Drilling and Completions are 82% complete. Drilling on the fifth of seven pads was completed in Q4/12. In early 2013 the sixth pad was drilled and the seventh pad is currently being drilled.
— First steam-in is targeted for Q4/13 and production is targeted to ramp up to 40,000 bbl/d in late 2014.
— On Kirby North Phase 1, detailed engineering is now in progress. Construction of the main access road has been completed and site preparation continues. A stratigraphic (“strat”) drilling program consisting of 50 wells is targeted for Q1/13. First steam-in is targeted for 2016. Full project sanction is expected in Q3/13.
– Planned drilling activity for 2013 includes 132 net thermal in situ wells and 1,022 net crude oil wells, excluding strat test and service wells.
– Canadian Natural has an active strat test well drilling program to delineate the reservoir characteristics for future projects. The Company targets to drill 463 strat wells in 2013.
– North America natural gas production for the year averaged 1,198 MMcf/d representing a decrease of 3% from 2011 levels. During Q4/12, natural gas production averaged 1,113 MMcf/d representing a decrease of 11% from Q4/11 and 5% from Q3/12. The decrease in production levels was primarily due to expected production declines reflecting Canadian Natural–s strategic decision to allocate capital to higher return crude oil projects. As well, the Company shut in a cumulative total of 40 MMcf/d of natural gas volumes as a result of weakened natural gas pricing. In Q4/12, production was restricted after ending fixed processing agreements for certain natural gas volumes to maintain flexible cost control in response to weakening gas pricing.
– During 2012, due to weak natural gas pricing, Canadian Natural reduced its capital expenditures related to natural gas. As a result, drilling and expansion at Septimus, the Company–s liquids rich Montney play, was deferred into 2013, with the anticipation of improved pricing. To date, the expansion is on track and is targeted for completion in late 2013 which will increase targeted natural gas sales levels from Septimus to 125 MMcf/d, yielding 12,200 bbl/d of liquids following processing through the plant and deep cut facilities.
– Canadian Natural is the second largest producer of natural gas in Canada and a significant owner and operator of natural gas infrastructure in Western Canada. The North America Company Gross proved plus probable natural gas reserve base of 5.57 Tcf generates operating free cash flow and presents significant upside potential for natural gas production and value when natural gas prices recover.
– Canadian Natural has a dominate Montney land position with over one million high quality net acres, the largest in the industry. In order to maximize the value of this important asset Canadian Natural has begun the process to monetize approximately 250,000 net acres (approximately 390 net sections) of our Montney land base in the liquids rich fairway in the Graham Kobes area of North East British Columbia. Under the process Canadian Natural will consider either an outright sale of the lands or a joint venture partner with LNG expertise to jointly develop the lands. If this process meets our internal targets and a transaction is completed, Canadian Natural will continue to have one of the largest undeveloped Montney land bases in Canada with lands contained in the two major areas of Septimus, British Columbia and North West Alberta.
International Exploration and Production
– Canadian Natural–s international assets provide light crude oil balance to the Company–s diverse portfolio and generated over $200 million of free cash flow in 2012.
– International crude oil production averaged 38,472 bbl/d during 2012 which was within the Company–s previously stated guidance of 38,000 bbl/d – 39,000 bbl/d for the year. Production volumes declined from 2011 as a result of the suspension of production at Banff/Kyle (North Sea) due to storm damage in Q4/11, maintenance activities on a third-party operated pipeline in the North Sea, natural field declines, and planned maintenance activities at Ninian (North Sea), Baobab and Espoir (Offshore Africa).
– Production is targeted to increase by approximately 6% in 2013. International light oil activities in 2013 will include a ramp up of drilling operations in the North Sea, the commencement of abandonment operations at Murchison in the North Sea, and commencement of the infill drilling program at Espoir, Offshore Africa.
– The Company continues with the partnering process for South Africa. Targeted drilling windows are from Q4/13 to Q1/14 and from Q4/14 to Q1/15.
North America Oil Sands Mining and Upgrading – Horizon
– Horizon Oil Sands achieved average annual SCO production of 86,077 bbl/d in 2012. Production volumes were 113% higher than 2011 volumes as the reliability of the Horizon plant steadily improved in 2012.
– Average SCO production of 83,079 bbl/d was achieved at Horizon during Q4/12. Production decreased 16% from Q3/12 as a result of the previously announced 12 day planned proactive maintenance activities completed in October. In late December, additional unplanned maintenance activities were performed on the OPPs which contributed to lower quarterly volumes.
– In January and February 2013, strong performance from Horizon resulted in average SCO volumes of approximately 113,000 bbl/d and 107,000 bbl/d, respectively. Q1/13 production guidance is targeted to range from 105,000 bbl/d to 111,000 bbl/d of SCO.
– The first major turnaround at Horizon is planned for May 2013. To ensure effective execution of the turnaround and to ensure greater reliability, the turnaround has been increased from 18 days to 24 days. 2013 annual guidance has not been affected and remains unchanged at 100,000 bbl/d to 108,000 bbl/d of SCO.
– Canadian Natural–s staged expansion to 250,000 bbl/d of SCO production capacity continues to progress on track. An update to the expansion at the end of Q4/12 is as follows:
— Overall Horizon expansion is 18% complete.
— Reliability – Tranche 2 is 86% complete. This project is targeted for completion in 2013; an additional of 5,000 bbl/d of production capacity will be added at completion.
— Directive 74 includes technological investment and research into tailings management. This portion remains on track and is currently 16% complete.
— Phase 2A is the coker expansion. The expansion is 47% complete, and is targeted to add 10,000 bbl/d of production capacity in 2015.
— Phase 2B is 8% complete. This phase includes lump sum contracts for major components such as gas/oil hydrotreatment, froth treatment and a hydrogen plant. This phase is targeted to add another 45,000 bbl/d of production capacity in 2016.
— Phase 3 is on track and engineering is underway. This phase is 8% complete, and includes the addition of supplementary extraction trains. This phase is targeted to increase production capacity by 80,000 bbl/d in 2017.
— Projects currently under construction are trending at or below 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 transportation and blending costs, excluding risk management activities.
– The WCS heavy crude oil differential (“WCS differential”) as a percent of WTI averaged 22% during 2012 compared with 18% in 2011. During Q4/12 the WCS differential averaged 21%, in line with the Company–s long term expectations. The Company anticipates continued volatility in the differential for the first half of 2013 and narrowing of the differential thereafter as additional heavy oil conversion and pipeline capacity come on stream.
– During October and November 2012, the WCS differential averaged 11% and 16% respectively, widening out to 34% in December 2012 as a result of unplanned pipeline capacity limitations and refinery-planned lower crude oil inventories at year-end. During January and February 2013, the WCS differential widened to average 37% but was partially offset by higher overall WTI pricing. For March 2013, the WCS differential has narrowed to average 29%.
– Canadian Natural contributed 157,000 bbl/d of its heavy crude oil stream to the WCS blend in 2012. The Company remains the largest contributor to the WCS blend, accounting for 53%.
– During 2012, Canadian natural gas production declined in response to lower pricing while US natural gas production remained steady throughout the year. Natural gas pricing recovered to AECO $2.89 in Q4/12 but benchmark pricing will continue to remain volatile until the demand from the power generation sector increases enough to offset strong North American supply.
NORTH WEST REDWATER UPGRADING AND REFINING
During Q4/12, the Redwater Partnership 50,000 bbl/d bitumen refinery (78,000 bbl/d of bitumen blend) was sanctioned by its owners (50% Canadian Natural). Work continues on the North West Redwater refinery and completion is targeted for mid-2016. The Company will also provide 12,500 bbl/d of bitumen feedstock to the refinery as a toll payer. There is potential to further expand the downstream capacity of the North West Redwater refinery from its 50,000 bbl/d of bitumen facility capacity in Phase 1 to 150,000 bbl/d of bitumen facility capacity.
The North West Redwater refinery asset strengthens the Company–s position by providing a competitive return on investment and by adding 50,000 bbl/d of bitumen conversion capacity in Alberta which will help reduce volatility in pricing all Western Canadian heavy crude oil.
FINANCIAL REVIEW
The Company continues to implement proven strategies and focuses on disciplined capital allocation. As a result, the financial position of Canadian Natural remains strong. Canadian Natural–s cash flow generation, credit facilities, diverse asset base and related capital expenditure programs, and commodity hedging policy all support a flexible financial position and provide the right financial resources for the near, mid and long term.
– The Company–s strategy is to maintain a diverse portfolio balanced across various commodity types. The Company achieved production of 658,973 BOE/d for Q4/12 with over 97% of production located in G8 countries.
– Canadian Natural has a strong balance sheet with debt to book capitalization of 26.0% and debt to EBITDA of 1.2x. At December 31, 2012, long-term debt amounted to $8.7 billion compared with $8.6 billion at December 31, 2011.
– Canadian Natural maintains significant financial stability and liquidity represented by approximately $3.66 billion in available unused bank lines at the end of the 2012.
– The Company–s commodity hedging program protects investment returns, ensures ongoing balance sheet strength and supports the Company–s cash flow for its capital expenditures programs. Through the use of collars, the Company has hedged 48% of its forecasted 2013 crude oil volumes; 200,000 bbl/d of crude oil volumes in Q1/13, and 250,000 bbl/d of crude oil volumes in Q2/13, Q3/13 and Q4/13. Details of the Company–s commodity hedging program can be found on the Company–s website at .
– During 2012, Canadian Natural purchased 11,012,700 common shares for cancellation at a weighted average price of $28.91 per common share.
– For 2013, the Board has approved a 19% dividend increase to C$0.125 per quarter, C$0.50 per share annualized. This will be the thirteenth consecutive year that the Company has announced an increased annual dividend distribution representing a compound annual growth rate of 21% over the period.
– In addition, the Company–s Board of Directors have directed Management to continue with an active program, subject to market conditions, to purchase for cancellation common shares under the Company–s Normal Course Issuer Bid at or above the levels of shares purchased in financial year 2012.
OUTLOOK
The Company forecasts 2013 production levels before royalties to average between 1,085 and 1,145 MMcf/d of natural gas and between 482,000 and 513,000 bbl/d of crude oil and NGLs. Q1/13 production guidance before royalties is forecast to average between 1,130 and 1,150 MMcf/d of natural gas and between 471,000 and 495,000 bbl/d of crude oil and NGLs. Detailed guidance on production levels, capital allocation and operating costs can be found on the Company–s website at .
CORPORATE ANNOUNCEMENTS
Board of Directors Changes
James S. Palmer has informed the Company of his decision after 16 years of continuous service as a Director, to not stand for re-election to the Board of Directors at the Annual and Special Meeting of Shareholder on May 2, 2013. During Mr. Palmer–s tenure with the Company, Canadian Natural has transitioned from a conventional oil and natural gas player based in western Canada to one of the largest independent crude oil and natural gas producers in the world with both domestic and international operations. Canadian Natural and the Board would like to thank Mr. Palmer for his valued wisdom, insight, guidance, leadership and dedication to the Company and its shareholders since his appointment as a director in 1997.
Management Changes
John G. Langille, Vice-Chairman, has announced his decision to retire from Canadian Natural effective May 2, 2013 immediately following the Annual and Special Meeting of Shareholders. John has served Canadian Natural for 37 years in various roles, most recently in the capacity of Vice-Chairman and prior to that as President. Through John–s untiring efforts and guidance, Canadian Natural has remained focused on our defined growth plan thereby creating value for our shareholders through targeting cost effective alternatives to developing our portfolio of projects and to being one of the most effective and efficient producers in our industry. Canadian Natural and the Board would like to thank John for his dedicated service and loyalty to the Company.
As part of the Canadian Natural–s management stewardship, high priority is assigned to succession planning to ensure the continued strength of the Company–s leadership team.
Tim S. McKay, currently Chief Operating Officer, will become Executive Vice-President and Chief Operating Officer. He will continue to be responsible for the Canadian Conventional and International operations, and in addition will now be responsible for Horizon operations.
Douglas A. Proll, currently Chief Financial Officer and Senior Vice-President, Finance will become Executive Vice-President. He will continue to be a senior member of the Company–s Management Committee and will have direct responsibility for certain non-financial departments and provide additional leadership in Investor Relations and other areas of stakeholder relations.
Corey B. Bieber, Vice-President Finance and Investor Relations will assume the role of Chief Financial Officer and Senior Vice-President, Finance. Corey joined Canadian Natural in 2001 and has been responsible for Treasury and Investor Relations since then and became a member of the Company–s Management Committee in 2009. In his new role, Corey will be responsible for all aspects of the finance functions at Canadian Natural.
The appointments of Mr. McKay, Mr. Bieber and Mr. Proll are effective March 28, 2013.
YEAR-END RESERVES
Determination of Reserves
For the year ended December 31, 2012 the Company retained Independent Qualified Reserves Evaluators (“Evaluators”), Sproule Associates Limited, Sproule International Limited (together as “Sproule”) and GLJ Petroleum Consultants Ltd. (“GLJ”), 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.
Corporate Total
– Company Gross proved crude oil, SCO, bitumen and NGL reserves increased 6% to 4.33 billion barrels. Company Gross proved natural gas reserves decreased 7% to 4.14 Tcf. Total proved reserves increased 4% to 5.02 billion BOE.
– Company Gross proved plus probable crude oil, SCO, bitumen and NGL reserves increased 6% to 6.92 billion barrels. Company Gross proved plus probable natural gas reserves decreased 5% to 5.79 Tcf. Total proved plus probable reserves increased 5% to 7.89 billion BOE.
– Company Gross proved reserve additions, including acquisitions, were 404 million barrels of crude oil, SCO, bitumen and NGL and 135 billion cubic feet of natural gas for 426 million BOE. The total proved reserve replacement ratio was 178%. The total proved reserve life index is 22.8 years.
– Company Gross proved plus probable reserve additions, including acquisitions, were 565 million barrels of crude oil, bitumen, SCO and NGL and 132 billion cubic feet of natural gas for 587 million BOE. The total proved plus probable reserve replacement ratio was 246%. The total proved plus probable reserve life index is 35.8 years.
– Proved undeveloped crude oil, SCO, bitumen and NGL reserves accounted for 31% of the corporate total proved reserves and proved undeveloped natural gas reserves accounted for 4% of the corporate total proved reserves.
North America Exploration and Production
– North America Company Gross proved crude oil, bitumen and NGL reserves increased 7% to 1.74 billion barrels. Company Gross proved natural gas reserves decreased 7% to 3.99 Tcf. Total proved BOE increased 3% to 2.41 billion barrels.
– North America Company Gross proved plus probable crude oil, bitumen and NGL reserves increased 16% to 3.08 billion barrels. Company Gross proved plus probable natural gas reserves decreased 5% to 5.57 Tcf. Total proved plus probable BOE increased 11% to 4.01 billion barrels.
– North America Company Gross proved reserve additions and revisions, including acquisitions, were 230 million barrels of crude oil, bitumen and NGL and 157 billion cubic feet of natural gas for 256 million BOE. The total proved reserve replacement ratio is 133%. The total proved reserve life index in 14.3 years.
– North America Company Gross proved plus probable reserve additions and revisions, including acquisitions, were 548 million barrels of crude oil, bitumen and NGL and 174 billion cubic feet of natural gas for 577 million BOE. The total proved plus probable reserve replacement ratio was 299%. The total proved plus probable reserve life index is 23.8 years.
– Proved undeveloped crude oil, bitumen and NGL reserves accounted for 38% of the North America total proved reserves and proved undeveloped natural gas reserves accounted for 8% of the North America total proved reserves.
– Thermal oil Company Gross proved reserves increased 9% to 1,066 million barrels primarily due to category transfers from probable undeveloped to proved undeveloped at Kirby North and new proved undeveloped additions at Primrose and Wolf Lake. Proved bitumen reserve additions and revisions were 128 million barrels. Total proved plus probable bitumen reserves increased 23% to 2,122 million barrels primarily due to proved plus probable undeveloped additions at Primrose and Wolf Lake and probable undeveloped additions at Grouse.
– Company Gross proved plus probable bitumen reserves additions and revisions were 432 million barrels.
North America Oil Sands Mining and Upgrading
– Company Gross proved synthetic crude oil reserves increased 6% to 2.26 billion barrels.
– Proved reserve additions were 167 million barrels primarily due to additional stratigraphic wells drilled in the north pit.
International Exploration and Production
– North Sea Company Gross proved reserves decreased 2% to 240 million BOE primarily due to production. North Sea Company Gross proved plus probable reserves are 349 million BOE.
– Offshore Africa Company Gross proved reserves decreased 7% to 115 million BOE primarily due to production. Offshore Africa Company Gross proved plus probable reserves are 177 million BOE.
Summary of Company Gross Crude Oil, Bitumen, Natural Gas & NGL Reserves
As of December 31, 2012
Forecast Prices and Costs
Summary of Company Net Crude Oil, Bitumen, Natural Gas & NGL Reserves
As of December 31, 2012
Forecast Prices and Costs
Reconciliation of Company Gross Reserves by Product
As of December 31, 2012
Forecast Prices and Costs
Reconciliation of Company Gross Reserves by Product
As of December 31, 2012
Forecast Prices and Costs
Reconciliation of Company Gross Reserves by Product
As of December 31, 2012
Forecast Prices and Costs
(1) Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests.
(2) Company Net reserves are working interest share after deduction of royalties and including any royalty interests.
(3) Forecast pricing assumptions utilized by the independent qualified reserves evaluators in the reserve estimates were provided by Sproule Associates Limited:
A foreign exchange rate of 1.001 US$/Cdn$ was used in the 2012 evaluation.
(4) Reserve additions are comprised of all categories of Company Gross reserve changes, exclusive of production.
(5) Reserve replacement ratio is the Company Gross reserve additions divided by the Company Gross production in the same period.
(6) A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.
MANAGEMENT–S DISCUSSION AND ANALYSIS
Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (the “Company”) in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words “believe”, “anticipate”, “expect”, “plan”, “estimate”, “target”, “continue”, “could”, “intend”, “may”, “potential”, “predict”, “should”, “will”, “objective”, “project”, “forecast”, “goal”, “guidance”, “outlook”, “effort”, “seeks”, “schedule”, “proposed” or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, operating costs, capital expenditures, income tax expenses and other guidance provided throughout this Management–s Discussion and Analysis (“MD&A”), constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including but not limited to the Horizon Oil Sands operations and future expansions, Primrose thermal projects, Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, construction of the proposed Keystone XL Pipeline from Hardisty, Alberta to the US Gulf Coast, the proposed Kinder Morgan Trans Mountain pipeline expansion from Edmonton, Alberta to Vancouver, British Columbia, and the construction and future operations of the North West Redwater bitumen upgrader and refinery also constitute forward-looking statements. This forward-looking information is based on annual budgets and multi-year forecasts, and is reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur.
In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and natural gas liquids (“NGLs”) reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates.
The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of the Company–s products; volatility of and assumptions regarding crude oil and natural gas prices; fluctuations in currency and interest rates; assumptions on which the Company–s current guidance is based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; the Company–s defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company–s and its subsidiaries– ability to secure adequate transportation for its products; unexpected disruptions or delays in the resumption of the mining, extracting or upgrading of the Company–s bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting or upgrading the Company–s bitumen products; availability and cost of financing; the Company–s and its subsidiaries– success of exploration and development activities and their ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies; production levels; imprecision of reserve estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital and operating costs); asset retirement obligations; the adequacy of the Company–s provision for taxes; and other circumstances affecting revenues and expenses.
The Company–s operations have been, and in the future may be, affected by political developments and by federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company–s assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company–s course of action would depend upon its assessment of the future considering all information then available.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by law, the Company assumes no obligation to update forward-looking statements, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or Management–s estimates or opinions change.
Management–s Discussion and Analysis
This MD&A of the financial condition and results of operations of the Company should be read in conjunction with the unaudited interim consolidated financial statements for the three months and year ended December 31, 2012 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2011.
All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company–s consolidated financial statements for the period ended December 31, 2012 and this MD&A have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board. This MD&A includes references to financial measures commonly used in the crude oil and natural gas industry, such as adjusted net earnings from operations, cash flow from operations, and cash production costs. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate its performance. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings, as determined in accordance with IFRS, as an indication of the Company–s performance. The non-GAAP measures adjusted net earnings from operations and cash flow from operations are reconciled to net earnings, as determined in accordance with IFRS, in the “Financial Highlights” section of this MD&A. The derivation of cash production costs is included in the “Operating Highlights – Oil Sands Mining and Upgrading” section of this MD&A. The Company also presents certain non-GAAP financial ratios and their derivation in the “Liquidity and Capital Resources” section of this MD&A.
A Barrel of Oil Equivalent (“BOE”) is derived by converting six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of this MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and synthetic crude oil.
Production volumes and per unit statistics are presented throughout this MD&A on a “before royalty” or “gross” basis, and realized prices are net of transportation and blending costs and exclude the effect of risk management activities. Production on an “after royalty” or “net” basis is also presented for information purposes only.
The following discussion refers primarily to the Company–s financial results for the three months and year ended December 31, 2012 in relation to the comparable periods in 2011 and the third quarter of 2012. The accompanying tables form an integral part of this MD&A. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2011, is available on SEDAR at , and on EDGAR at . This MD&A is dated March 6, 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” presented below lists 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” presented lists 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 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 fourth quarter of 2012, the Company repaid US$350 million of 5.45% unsecured notes. During the third quarter of 2011, the Company repaid US$400 million of 6.70% unsecured notes.
(5) 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 third quarter of 2012, the UK government enacted legislation to restrict the combined corporate and supplementary income tax rate relief on UK North Sea decommissioning expenditures to 50%, resulting in an increase in the Company–s deferred income tax liability of $58 million. During the first quarter of 2011, the UK government enacted legislation to increase the corporate income tax rate charged on profits from UK North Sea crude oil and natural gas production from 50% to 62%. The Company–s deferred income tax liability was increased by $104 million with respect to this tax rate change.
Cash Flow from Operations
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
Net earnings for the year ended December 31, 2012 were $1,892 million compared with $2,643 million for the year ended December 31, 2011. Net earnings for the year ended December 31, 2012 included net after-tax income of $274 million compared with $103 million for the year ended December 31, 2011 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, the impact of a realized foreign exchange gain on repayment of long-term debt and the impact of statutory tax rate and other legislative changes on deferred income tax liabilities. Excluding these items, adjusted net earnings from operations for the year ended December 31, 2012 were $1,618 million compared with $2,540 million for the year ended December 31, 2011.
Net earnings for the fourth quarter of 2012 were $352 million compared with $832 million for the fourth quarter of 2011 and $360 million for the third quarter of 2012. Net earnings for the fourth quarter of 2012 included net after-tax expenses of $7 million compared with $140 million for the fourth quarter of 2011 and net after-tax income of $7 million for the third quarter of 2012 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, the impact of a realized foreign exchange gain on repayment of long-term debt and the impact of statutory tax rate and other legislative changes on deferred income tax liabilities. Excluding these items, adjusted net earnings from operations for the fourth quarter of 2012 were $359 million compared with $972 million for the fourth quarter of 2011 and $353 million for the third quarter of 2012.
The decrease in adjusted net earnings for the year ended December 31, 2012 from the year ended December 31, 2011 was primarily due to:
– lower crude oil and NGLs and natural gas netbacks;
– lower realized synthetic crude oil (“SCO”) prices;
– higher depletion, depreciation and amortization expense; and
– higher realized risk management losses;
partially offset by:
– higher crude oil and SCO sales volumes in the North America and Oil Sands Mining and Upgrading segments.
The decrease in adjusted net earnings for the fourth quarter of 2012 from the fourth quarter of 2011 was primarily due to:
– lower crude oil and NGLs and natural gas netbacks;
– lower realized SCO prices;
– lower natural gas sales volumes;
– lower SCO sales volumes in the Oil Sands Mining and Upgrading segment;
– higher depletion, depreciation and amortization expense; and
– the impact of a stronger Canadian dollar;
partially offset by:
– higher crude oil sales volumes in the North America segment.
The adjusted net earnings for the fourth quarter of 2012 were comparable with the third quarter of 2012.
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 year ended December 31, 2012 was $6,013 million compared with $6,547 million for the year ended December 31, 2011. Cash flow from operations for the fourth quarter of 2012 was $1,548 million compared with $2,158 million for the fourth quarter of 2011 and $1,431 million for the third quarter of 2012. The fluctuations in cash flow from operations from the comparable periods was primarily due to the factors noted above relating to the fluctuations in adjusted net earnings, excluding depletion, depreciation and amortization expense, as well as due to the impact of cash taxes.
Total production before royalties for the year ended December 31, 2012 increased 9% to 654,665 BOE/d from 598,526 BOE/d for the year ended December 31, 2011. Total production before royalties for the fourth quarter of 2012 was comparable with the fourth quarter of 2011 and the third quarter of 2012.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company–s quarterly results for the eight most recently completed quarters:
Volatility in the quarterly net earnings over the eight most recently completed quarters was primarily due to:
– Crude oil pricing – The impact of fluctuating demand, inventory storage levels and geopolitical uncertainties on worldwide benchmark pricing, the impact of the WCS Heavy Differential from West Texas Intermediate (“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 oil drilling program, and the impact of the suspension and recommencement of production at Horizon. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the North Sea and Offshore Africa, and payout of the Baobab field in May 2011.
– Natural gas sales volumes – Fluctuations in production due to the Company–s strategic decision to reduce natural gas drilling activity in North America and the allocation of capital to higher return crude oil projects, as well as natural decline rates, shut-in natural gas production due to pricing and the impact and timing of acquisitions.
– Production expense – Fluctuations primarily due to the impact of the demand for services, fluctuations in product mix, the impact of seasonal costs that are dependent on weather, production and cost optimizations in North America, acquisitions of natural gas producing properties in 2011 that had higher operating costs per Mcf than the Company–s existing properties, and the suspension and recommencement of production at Horizon.
– Depletion, depreciation and amortization – Fluctuations due to changes in sales volumes, proved reserves, asset retirement obligations, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company–s proved undeveloped reserves, and the impact of the suspension and recommencement of production at Horizon.
– Share-based compensation – Fluctuation