CALGARY, ALBERTA — (Marketwire) — 11/08/12 — Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ)
Commenting on third quarter results, Canadian Natural–s Vice-Chairman John Langille stated, “During the first nine months of 2012 we effectively executed a balanced capital budget. Our large proved plus probable reserve base (7.5 billion barrels of oil equivalent) delivered $4.5 billion of cash flow ensuring we maintain a strong balance sheet with debt to book capitalization at 26% and debt to EBITDA of 1.1 times. This strong financial position supports our ability to drive effective capital allocation, efficiently control costs and continue implementing our successful strategy.
As part of our successful strategy we have sanctioned the North West Redwater refinery project. This project strengthens our position by not only providing a competitive return on investment but also by adding 50,000 bbl/d of heavy crude oil conversion capacity in Alberta which will help reduce volatility in pricing all Western Canadian heavy crude oil.”
Steve Laut, President of Canadian Natural continued, “We had a solid operating quarter and we met or exceeded production guidance in all areas of the business. The Company achieved strong production volumes, up 9% from the third quarter of last year, due to our successful heavy and light crude oil drilling programs and our oil sands operations, both thermal in situ and Horizon mining. This is impressive considering the Company deferred an additional $230 million of capital this quarter, over and above the $680 million that was previously deferred, totalling $910 million of reduced capital expenditures since mid-2012.
During the third quarter, we made substantial progress in driving our mid and long term potential assets forward. The Horizon expansion is making solid progress and tracking below cost estimates. At Pelican Lake, we continue to roll out our leading edge polymer flood and are seeing strong production response. We achieved 67% construction completion at Kirby South Phase 1 and target first steam in late 2013.
Additionally the Company has added 31,570 net acres of thermal in situ lands contiguous to our Kirby land holdings. The additional lands contain significant SAGD resource potential within the McMurray reservoir creating long term value for the Company. It is expected that these lands will increase overall production capacity at our thermal in situ operations that currently is targeted to add 500,000 barrels per day of bitumen over the next fifteen years.
Canadian Natural is in an excellent position. We have a proven strategy that works, and are focused on effective and efficient operations in all areas. Our vast resource base, strong technical expertise, and financial resources will facilitate our ability to significantly grow cash flow and maximize returns for our shareholders.”
QUARTERLY HIGHLIGHTS
– During Q3/12, the Company achieved quarterly production of 667,616 BOE/d, representing an increase of 9% over Q3/11, and met or exceeded production guidance in all areas of the business.
– The Company–s total crude oil and NGLs production during Q3/12 was 469,168 bbl/d, representing an increase of 16% over Q3/11 and comparable to Q2/12. The increase from Q3/11 was primarily due to a strong primary heavy crude oil drilling program, the timing of production cycles in bitumen (“thermal in situ”), and safe, steady and reliable operations at Horizon. Q3/12 production volumes remained consistent with Q2/12 volumes and were primarily driven by increased heavy crude oil production, increased Pelican Lake crude oil production and increased thermal in situ production offset by lower synthetic crude oil (“SCO”) production.
– During Q3/12, total natural gas production for the Company was 1,191 MMcf/d representing a decrease of 5% from both Q3/11 and Q2/12 levels. The decrease in production from Q3/11 and Q2/12 was primarily a result of natural declines and 40 MMcf/d of cumulative shut-in natural gas volumes reflecting the Company–s strategic decision to allocate capital to higher return crude oil projects due to low natural gas prices.
– Canadian Natural generated quarterly cash flow of $1.43 billion, compared to $1.77 billion in Q3/11 and $1.75 billion in Q2/12. Cash flow decreased from Q3/11 primarily resulting from lower crude oil and NGLs and natural gas netbacks and lower SCO pricing partially offset by higher crude oil and SCO sales volumes. The decrease in cash flow from Q2/12 was primarily due to lower SCO sales volumes and lower crude oil and NGLs netbacks. These factors, along with the impact of a stronger Canadian dollar and non-operational realized risk management losses were partially offset by higher crude oil sales volumes in North America and higher natural gas prices.
– Adjusted net earnings from operations for the quarter were $353 million, compared with adjusted net earnings of $719 million in Q3/11 and $606 million in Q2/12. Changes in adjusted net earnings reflect the changes in cash flow from operations.
– The Company reduced targeted 2012 capital spending by an additional $230 million in the quarter, resulting in total capital spending reductions of $910 million or 12%, compared to the updated capital budget announced in May 2012. At the same time, the mid-point of total BOE production volume guidance has decreased only 1% for 2012. This illustrates the strength of the Company–s asset base and ability to maintain capital flexibility while allocating capital to the highest return projects.
– Operating highlights for Q3/12 include the following with further details included in the Operations Review sections.
— Primary heavy crude oil operations achieved production volumes that totaled over 128,000 bbl/d, resulting in the seventh consecutive quarter of record production. Production increased by 26% compared with Q3/11.
— North America light crude oil and NGLs quarterly production increased 15% from Q3/11.
— Reservoir performance at Pelican Lake continues to be positive as production volumes of approximately 41,000 bbl/d in Q3/12 were achieved, an increase of 8% over Q3/11 volumes.
— In Q3/12, thermal in situ production grew 8% from the previous quarter to approximately 102,000 bbl/d.
— Kirby South Phase 1 is progressing ahead of plan. All major equipment and modules have been delivered and installed on site with overall construction progress ahead of schedule.
— In Q3/12, solid production volumes were achieved at Horizon Oil Sands (“Horizon”), exceeding 99,200 bbl/d.
— Canadian Natural–s staged expansion to 250,000 bbl/d of SCO production capacity at Horizon continues to progress on track.
– Subsequent to Q3/12, North West Redwater Partnership and its owners (50% Canadian Natural) completed the sanctioning process for the construction of a 50,000 bbl/d bitumen refinery. Simultaneously, the feedstock providers (Canadian Natural for 12,500 bbl/d and Alberta Petroleum Marketing Commission for 37,500 bbl/d) approved the target toll amounts and have now committed to the 30 year tolling agreement.
– To date in 2012, Canadian Natural has purchased 7,825,200 common shares for cancellation at a weighted average price of $29.22 per common share.
– Declared a quarterly cash dividend on common shares of $0.105 per common share payable January 1, 2013.
– Canadian Natural will release its 2013 budget details on Tuesday, December 4, 2012. The Company will provide forward looking information on its 2013 operating year.
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 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
Drilling activity (number of wells)
North America Exploration and Production
North America crude oil and NGLs
– Production averaged 332,895 bbl/d in Q3/12 representing an increase of 9% from Q3/11 and an increase of 5% from Q2/12. The increase in production from Q3/11 was a result of a successful primary heavy crude oil drilling program and the timing of thermal in situ production cycles. The increase in production from Q2/12 was a result of strong heavy crude oil production, increased Pelican Lake volumes and the continuing ramp up of thermal in situ production as pads re-entered the production cycle.
– Primary heavy crude oil currently provides the highest return on capital projects in Canadian Natural–s portfolio. Primary heavy crude oil operations achieved production volumes that totaled over 128,000 bbl/d, resulting in the seventh consecutive quarter of record production. Production increased by 26% and 5% compared with Q3/11 and Q2/12 levels respectively, primarily due to a successful drilling program and strong production results from Woodenhouse, a new non-traditional primary heavy crude oil area located 75 kilometers north of Pelican Lake.
— The production profiles at Woodenhouse have been better than anticipated. In October 2012, production averaged 9,300 bbl/d and exit rate production for 2012 is targeted at approximately 12,600 bbl/d. In 2012, 71 wells have been drilled at Woodenhouse and the Company targets to drill 15 additional wells by year-end.
— Canadian Natural targets to drill 241 net primary heavy crude oil wells (including Woodenhouse) in Q4/12 for a targeted record of 901 total net wells in 2012, 93 more net wells than the original budget. The Company has further increased its targeted annual production guidance by 5% to an increase of 22% over 2011 production volumes.
— Canadian Natural continues to demonstrate efficient and effective operations in primary heavy crude oil. Low quarterly operating costs of $14.27/bbl were achieved in Q3/12 and continue to result in high netbacks and high value production contributing to the Company–s significant cash flow.
– North America light crude oil and NGLs quarterly production increased 15% from Q3/11 as a result of a successful light oil drilling program and increased production from Septimus. North America light crude oil and NGLs is a significant part of Canadian Natural–s balanced portfolio, averaging approximately 62,600 bbl/d in the quarter.
– Reservoir performance at Pelican Lake continues to be positive as production volumes of approximately 41,000 bbl/d in Q3/12 were achieved, an increase of 8% over Q3/11 volumes.
— The Company achieved over 37,000 bbl/d in Q2/12, approximately 41,000 bbl/d in Q3/12 and exit rates for 2012 are targeted to be approximately 43,000 bbl/d, a 16% increase from Q2/12 production volumes.
— Construction of the 25,000 bbl/d battery expansion is targeted to be on stream by Q2/13 and will support production growth to over 60,000 bbl/d targeted by 2015/16.
— Pelican Lake continues to achieve low quarterly operating costs at $10.69/bbl in Q3/12, which result in high netbacks and high value production contributing to the Company–s significant cash flow.
— Ultimate recovery from this world class pool is targeted to be 561 million barrels (363 million barrels of proved plus probable reserves and 198 million barrels of best estimate contingent resources) of additional crude oil through a disciplined multi-year expansion plan.
– 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.
— In Q3/12, thermal in situ production grew 8% from the previous quarter to approximately 102,000 bbl/d.
— The Company achieved over 94,000 bbl/d in Q2/12, approximately 102,000 bbl/d in Q3/12 and exit rates for 2012 are targeted to be approximately 119,500 bbl/d, a 27% increase from Q2/12 production volumes.
— Total quarterly operating costs, including energy costs, for the quarter were $8.84/bbl in Q3/12, which is industry leading for thermal in situ and demonstrates the Company–s commitment to operational excellence. As a result, the Company achieves high netbacks and high volume production contributing to the Company–s significant cash flow.
— Kirby South Phase 1 is progressing ahead of plan. 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 Q3/12 is as follows:
— Overall project is 67% complete.
— Module assembly is 96% complete.
— Overall construction is 58% complete.
— Drilling is 73% complete. Drilling on the fourth of seven pads was completed in Q3/12 and the fifth pad was rig released in early Q4/12.
— First steam-in is targeted for late 2013 and production is targeted to ramp up to 40,000 bbl/d in 2014.
— Over the past twelve months and through 3 separate transactions, 31,570 net acres of additional leases adjacent to Canadian Natural–s Kirby In Situ Oil Sands Expansion Project (“Kirby Project”) were acquired, adding best estimate contingent resources of 340 million barrels of bitumen. The Company is in the early stages of integrating the acquired lands into the development plan and is expecting to increase production capacity for future phases in Kirby North and Kirby South beyond current estimates. The Company expects to gain significant capital and operating synergies within the Kirby Project, which will create the potential to drive exploitation opportunities similar to those seen at Primrose over the last decade.
— On Kirby North Phase 1, engineering design specifications are complete and the transition to detailed engineering is now in progress. Critical long lead items have been ordered and the central plant site has been cleared. First steam-in is targeted for early 2016.
— At Grouse, engineering is on track. The design basis memorandum engineering is complete and the transition to engineering design specifications is now in progress. First steam-in is targeted for late 2017.
– For Q4/12, the Company plans to drill 42 net thermal in situ wells and 302 net crude oil wells, excluding strat test and service wells.
– North America crude oil and NGLs quarterly operating costs decreased to $12.52/bbl in Q3/12 from $13.10/bbl in Q2/12. The decrease was primarily due to reduced primary heavy crude oil operating costs as a result of strategic capital investments made during the first half of 2012 and the timing of thermal in situ production cycles.
North America natural gas
– North America natural gas production for the quarter averaged 1,169 MMcf/d representing a decrease of 5% from both Q3/11 and Q2/12 production levels. The decrease in production levels was a result of natural declines and 40 MMcf/d of cumulative shut-in natural gas volumes reflecting the Company–s strategic decision to allocate capital to higher return crude oil projects.
– The Company reduced capital spending on natural gas by an additional $45 million in the quarter, resulting in total capital spending reductions of $345 million or 42% for 2012 compared to the original capital budget while the mid-point of production volume guidance decreased 6% in 2012 compared to the original capital budget. This illustrates the strength of the Company–s asset base and ability to maintain capital flexibility and allocate capital to the highest return projects.
– North America natural gas quarterly operating costs increased to $1.28/Mcf in Q3/12 from $1.13/Mcf in Q2/12 as a result of reduced volumes, seasonal maintenance activity, increased property taxes and lease rentals.
– Canadian Natural is the second largest natural gas producer in Canada and has an extensive land base where it demonstrates efficient and effective operations. The Company–s vast land base of both conventional and unconventional natural gas assets and ownership of infrastructure favorably positions the Company to increase drilling activity and production volumes once gas prices strengthen. Canadian Natural–s significant unconventional assets include approximately 1,044,000 net acres in the Montney and approximately 500,000 net acres in the Duvernay.
International Exploration and Production
– North Sea crude oil production averaged 19,502 bbl/d during Q3/12 representing a decrease of 26% compared with Q3/11 and an increase of 11% compared with Q2/12. The decrease from Q3/11 was primarily due to suspended operations at Banff/Kyle, planned maintenance on a third-party operated pipeline, and planned maintenance turnarounds at the Ninian platforms that commenced late in Q3/12. The increase from Q2/12 was primarily due to partial recovery of production volumes following the unplanned shutdown of the Ninian platforms in Q2/12 as a result of a third-party pipeline outage.
– Production in Offshore Africa averaged 17,566 bbl/d during Q3/12 representing a decrease of 22% compared with Q3/11 and a decrease of 15% compared with Q2/12. The decrease from Q3/11 and Q2/12 production volumes was primarily due to natural declines and a planned 9 day turnaround at Baobab. A planned 15 day turnaround at Espoir is scheduled in Q4/12.
– Canadian Natural–s eight well infill drilling program at the Espoir Field is progressing. The drilling rig has arrived in Cote d–Ivoire and preparations are currently being undertaken to commence drilling. The Company targets first oil in Q2/13 ramping up to production of 6,500 BOE/d at the completion of the Espoir drilling program, offsetting natural declines. The cost of this program is targeted at $24,000 per flowing BOE.
– Conversion of the license of the Company–s 100% working interest block in South Africa has been completed and all regulatory requirements to drill a well are complete. 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 continued to demonstrate solid operational performance in the quarter. Production averaged 99,205 bbl/d, representing a 97% increase from Q3/11 and a 14% decrease from Q2/12. The increase from Q3/11 was due to improved steady operations at Horizon, and the decrease from Q2/12 resulted from the Company–s decision to operate at restricted rates for a portion of Q3/12 to ensure safe, steady and reliable operations in anticipation of the proactive planned maintenance that was completed in Q4/12.
– Previously planned maintenance at Horizon originally scheduled to occur in late Q3/12 was shifted into Q4/12 (October) to optimize the benefit of the outage and address potential risks associated with the winter season. The planned outage, scheduled for twelve days in the month of October, was completed on schedule and on cost. Production was returned to 115,000 bbl/d and then temporarily reduced to proactively allow tank volumes and overall performance to reach optimal levels not yet achieved following the ramp up. The decision to temporarily reduce production reflects the Company–s commitment to increasing overall reliability going forward. Horizon production guidance for 2012 has been reduced to range from 87,000 bbl/d to 89,000 bbl/d. However, overall long term production volumes are expected to increase because of these proactive actions.
– The Company–s focus on operational discipline and proactive maintenance activities will, over time, deliver increasing levels of reliability resulting in more effective and efficient operations, and lower operating costs at the plant. In Q3/12 quarterly operating costs averaged $42.69/bbl, which were primarily a result of lower production volumes and one-time costs.
– 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 Q3/12 is as follows:
— Overall Horizon expansion is 15% complete.
— Reliability – Tranche 2 is 84% complete.
— Directive 74 and Technology are 14% complete.
— Phase 2A is 39% complete.
— Phase 2B is 6% complete.
— Phase 3 is 6% complete.
— Thus far, four lump sum contracts have been awarded and projects currently under construction are trending at or below cost estimates.
MARKETING
– The WCS heavy crude oil differential as a percent of WTI was seasonally normal, averaging 24% in Q3/12, and in line with the Company–s long term expectations and well below historical averages. The WCS heavy differential remained unchanged from Q2/12. The Company anticipates continued volatility in the differential in Q4/12 and narrowing of the differential thereafter as additional conversion and pipeline capacity come on stream.
– For December 2012, heavy crude oil currently trades at a US$6.00 premium (7% premium) to WTI on the US Gulf Coast (“USGC”) and at a US$30.00 discount (35% discount) at Hardisty reflecting the logistical constraints at Cushing, which are currently being debottlenecked.
— Canadian Natural ships approximately 20,000 bbl/d of heavy crude oil via a combination of pipelines to USGC markets and receives Mayan based pricing for these barrels.
— Approximately 10,000 bbl/d of heavy crude oil is railed to USGC markets and receives significantly higher netbacks than the traditional heavy crude oil markets.
— This highlights the strong demand for Gulf Coast refiners to use heavy crude oil blends as feedstock, and the value to Canadian producers reaching the Gulf Coast.
– During Q3/12, Canadian Natural contributed 155,000 bbl/d of its heavy crude oil stream to the WCS blend. The Company is the largest contributor of the WCS blend, accounting for 55%.
– Natural gas pricing remains weak as compared to previous year pricing. In response, Canadian production has declined while US production remains steady through 2012. AECO benchmark natural gas prices strengthened in Q3/12 compared with Q2/12 due to increased demand from the power generation sector and increased seasonal demand.
NORTH WEST REDWATER UPGRADING AND REFINING
Subsequent to Q3/12, North West Redwater Partnership and its owners (50% Canadian Natural) completed the sanctioning process for the construction of a 50,000 bbl/d bitumen refinery. Simultaneously, the feedstock providers (Canadian Natural for 12,500 bbl/d and Alberta Petroleum Marketing Commission for 37,500 bbl/d) approved the target toll amounts and have now committed to the 30 year tolling agreement. Canadian Natural will earn a return on the project of 10% on its equity investment, and additional margin on any excess capacity available over design capacity. Based on sanction capital for the project, the majority of equity has already been contributed to the partnership. Target commencement of deliveries is mid-2016.
The North West Redwater refinery project strengthens the Company–s position by not only providing a competitive return on investment but by also adding 50,000 bbl/d of bitumen conversion capacity in Alberta which will help reduce volatility in pricing all Western Canadian heavy crude oil. There is potential to further expand the downstream capacity of the North West Redwater refinery project from its 50,000 bbl/d of bitumen facility capacity in Phase 1 to 150,000 bbl/d of bitumen facility capacity.
FINANCIAL REVIEW
The financial position of Canadian Natural remains strong as the Company continues to implement proven strategies and focuses on disciplined capital allocation. 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 667,616 BOE/d for the quarter with over 97% of production located in G8 countries.
– Canadian Natural has a strong balance sheet with debt to book capitalization of 26% and debt to EBITDA of 1.1x. At September 30, 2012, long-term debt amounted to $8.4 billion compared with $8.6 billion at December 31, 2011.
– Canadian Natural maintains significant financial stability and liquidity represented by approximately $4.26 billion in available unused bank lines at the end of the quarter.
– 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. The Company has hedged approximately 60% of the remaining crude oil volumes forecasted for 2012, 150,000 bbl/d of crude oil volumes for the first half of 2013, and 100,000 bbl/d of crude oil volumes for the second half of 2013 through a combination of puts and collars.
– To date in 2012, Canadian Natural has purchased 7,825,200 common shares for cancellation at a weighted average price of $29.22 per common share.
– Declared a quarterly cash dividend on common shares of $0.105 per common share payable January 1, 2013.
OUTLOOK
The Company forecasts 2012 production levels before royalties to average between 1,222 and 1,229 MMcf/d of natural gas and between 452,000 and 460,000 bbl/d of crude oil and NGLs. Q4/12 production guidance before royalties is forecast to average between 1,145 and 1,165 MMcf/d of natural gas and between 467,000 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 .
MANAGEMENT–S DISCUSSION AND ANALYSIS
Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (the “Company”) in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words “believe”, “anticipate”, “expect”, “plan”, “estimate”, “target”, “continue”, “could”, “intend”, “may”, “potential”, “predict”, “should”, “will”, “objective”, “project”, “forecast”, “goal”, “guidance”, “outlook”, “effort”, “seeks”, “schedule” or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes and costs, royalties, operating costs, capital expenditures, income tax expenses and other guidance provided throughout this Management–s Discussion and Analysis (“MD&A”), constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including but not limited to the Horizon Oil Sands operations and future expansions, Primrose, Pelican Lake, the Kirby Thermal Oil Sands Project, 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 and natural gas reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates.
The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of the Company–s products; volatility of and assumptions regarding crude oil and natural gas prices; fluctuations in currency and interest rates; assumptions on which the Company–s current guidance is based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; the Company–s defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company–s and its subsidiaries– ability to secure adequate transportation for its products; unexpected 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 natural gas liquids (“NGLs”) not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital and operating costs); asset retirement obligations; the adequacy of the Company–s provision for taxes; and other circumstances affecting revenues and expenses.
The Company–s operations have been, and in the future may be, affected by political developments and by federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company–s assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company–s course of action would depend upon its assessment of the future considering all information then available.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by law, the Company assumes no obligation to update forward-looking statements, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or Management–s estimates or opinions change.
Management–s Discussion and Analysis
This MD&A of the financial condition and results of operations of the Company should be read in conjunction with the unaudited interim consolidated financial statements for the three and nine months ended September 30, 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 September 30, 2012 and this MD&A have been prepared in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board. Unless otherwise stated, 2010 comparative figures have been restated in accordance with IFRS issued as at December 31, 2011. 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 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. 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 and nine months ended September 30, 2012 in relation to the comparable periods in 2011 and the second quarter of 2012. The accompanying tables form an integral part of this MD&A. This MD&A is dated November 6, 2012. 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 .
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 nine months ended September 30, 2012 amounted to $1,540 million compared with $1,811 million for the nine months ended September 30, 2011. Net earnings for the nine months ended September 30, 2012 included net after-tax income of $281 million compared with net after-tax income of $243 million for the nine months ended September 30, 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 nine months ended September 30, 2012 were $1,259 million compared with $1,568 million for the nine months ended September 30, 2011.
Net earnings for the third quarter of 2012 were $360 million compared with $836 million for the third quarter of 2011 and $753 million for the second quarter of 2012. Net earnings for the third quarter of 2012 included net after-tax income of $7 million compared with $117 million for the third quarter of 2011 and $147 million for the second 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 third quarter of 2012 were $353 million compared with $719 million for the third quarter of 2011 and $606 million for the second quarter of 2012.
The decrease in adjusted net earnings for the three and nine months ended September 30, 2012 from the comparable periods in 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
– 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; and
– the impact of a weaker Canadian dollar.
The decrease in adjusted net earnings for the third quarter of 2012 from the second quarter of 2012 was primarily due to:
– lower SCO sales volumes in the Oil Sands Mining and Upgrading segment;
– lower crude oil and NGLs netbacks;
– the impact of a stronger Canadian dollar; and
– realized risk management losses;
partially offset by:
– higher crude oil sales volumes in the North America segment; and
– lower depletion, depreciation and amortization expense.
The impacts of share-based compensation, risk management activities and changes in foreign exchange rates are expected to continue to contribute to quarterly volatility in consolidated net earnings and are discussed in detail in the relevant sections of this MD&A.
Cash flow from operations for the nine months ended September 30, 2012 was $4,465 million compared with $4,389 million for the nine months ended September 30, 2011. Cash flow from operations for the third quarter of 2012 was $1,431 million compared with $1,767 million for the third quarter of 2011 and $1,754 million for the second 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 decrease in adjusted net earnings, excluding depletion, depreciation and amortization expense.
Total production before royalties for the nine months ended September 30, 2012 increased 13% to 653,220 BOE/d from 578,618 BOE/d for the nine months ended September 30, 2011. Total production before royalties for the third quarter of 2012 increased 9% to 667,616 BOE/d from 612,575 BOE/d for the third quarter of 2011, and decreased 2% from 679,607 BOE/d for the second quarter of 2012. Production for the third quarter of 2012 was within the Company–s previously issued guidance.
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 (loss) over the eight most recently completed quarters was primarily due to:
– Crude oil pricing – The impact of fluctuating demand, inventory storage levels and geopolitical uncertainties on worldwide benchmark pricing, the impact of the WCS Heavy Differential 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 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 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, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company–s proved undeveloped reserves, the impact of the suspension and recommencement of production at Horizon and the impact of impairments at the Olowi field in offshore Gabon.
– Share-based compensation – Fluctuations due to the determination of fair market value based on the Black-Scholes valuation model of the Company–s share-based compensation liability.
– Risk management – Fluctuations due to the recognition of gains and losses from the mark-to-market and subsequent settlement of the Company–s risk management activities.
– Foreign exchange rates – Changes in the Canadian dollar relative to the US dollar that impacted the realized price the Company received for its crude oil and natural gas sales, as sales prices are based predominately on US dollar denominated benchmarks. Fluctuations in realized and unrealized foreign exchange gains and losses are 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.
BUSINESS ENVIRONMENT
Commodity Prices
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$96.20 per bbl for the nine months ended September 30, 2012 and was comparable with the nine months ended September 30, 2011. WTI averaged US$92.19 per bbl for the third quarter of 2012, an increase of 3% from US$89.81 per bbl for the third quarter of 2011 and was comparable with the second quarter of 2012. WTI pricing was reflective of the political instability in the Middle East with growing tensions between Israel and Iran creating instability in the crude price; partially offset by declining optimism in the United States economy, the European debt crisis, and lower than expected growth in Asian demand.
Crude oil sales contracts for the Company–s North Sea and Offshore Africa segments are typically based on Dated Brent (“Brent”) pricing, which is representative of international markets and overall world supply and demand. Brent averaged US$112.07 per bbl for the nine months ended September 30, 2012 and was comparable with the nine months ended September 30, 2011. Brent averaged US$109.57 per bbl for the third quarter of 2012, a decrease of 3% compared with US$113.46 per bbl for the third quarter of 2011 and was comparable with the second quarter of 2012. The higher Brent pricing relative to WTI was due to logistical constraints and high inventory levels of crude oil at Cushing. The differential is expected to narrow with the expansion of the Seaway pipeline in the first quarter of 2013.
The WCS Heavy Differential averaged 23% for the nine months ended September 30, 2012 compared with 20% for the nine months ended September 30, 2011. The WCS Heavy Differential averaged 24% for the second and third quarters of 2012 compared with 20% in the third quarter of 2011. The WCS Heavy Differential widened from the comparable periods in 2011 as a result of planned and unplanned maintenance at key refineries accessible by Canadian crude oil.
The Company uses condensate as a blending diluent for heavy crude oil pipeline shipments. During the third quarter of 2012, condensate prices continued to trade at a premium to WTI, similar to prior periods, reflecting normal seasonality.
The Company anticipates continued volatility in crude oil pricing benchmarks due to supply and demand factors, geopolitical events, and the timing and extent of the economic recovery. The WCS Heavy Differential is expected to continue to reflect seasonal demand fluctuations, changes in transportation logistics, and refinery utilization and shutdowns.
NYMEX natural gas prices averaged US$2.62 per MMBtu for the nine months ended September 30, 2012, a decrease of 38% from US$4.23 per MMBtu for the nine months ended September 30, 2011. NYMEX natural gas prices averaged US$2.82 per MMBtu for the third quarter of 2012, a decrease of 33% from US$4.19 per MMBtu for the third quarter of 2011, and an increase of 25% from US$2.26 per MMBtu for the second quarter of 2012.
AECO natural gas prices for the nine months ended September 30, 2012 averaged $2.07 per GJ, a decrease of 42% from $3.55 per GJ for the nine months ended September 30, 2011. AECO natural gas prices for the third quarter of 2012 averaged $2.08 per GJ, a decrease of 41% from $3.53 per GJ for the third quarter of 2011, and an increase of 20% from $1.74 per GJ for the second quarter of 2012.
During the third quarter of 2012, natural gas prices continued to be weak. While Canadian production has declined in response to low prices, US production has held steady during 2012. The AECO natural gas price has increased from the second quarter of 2012 as a result of a shift to higher utilization of gas fired electric generators supported by the low natural gas prices, and higher weather related gas demand resulting from warmer than normal summer temperatures.
DAILY PRODUCTION, before royalties
DAILY PRODUCTION, net of royalties
The Company–s business approach is to maintain large project inventories and production diversification among each of the commodities it produces; namely natural gas, light and medium crude oil and NGLs, Pelican Lake heavy crude oil, primary heavy crude oil, bitumen (thermal oil) and SCO.
Crude oil and NGLs production for the nine months ended September 30, 2012 increased 20% to 445,140 bbl/d from 370,439 bbl/d for the nine months ended September 30, 2011. Crude oil and NGLs production for the third quarter of 2012 increased 16% to 469,168 bbl/d from 403,900 bbl/d for the third quarter of 2011 and was comparable with the second quarter of 2012. The increase in production from the comparable periods in 2011 was primarily related to increased production at Horizon, the impact of a strong heavy crude oil drilling program, and the cyclic nature of the Company–s thermal operations. Crude oil and NGLs production in the third quarter of 2012 was within the Company–s previously issued guidance of 451,000 to 480,000 bbl/d.
Natural gas production for the nine months ended September 30, 2012 averaged 1,248 MMcf/d and was comparable with the nine months ended September 30, 2011. Natural gas production for the third quarter of 2012 decreased by 5% to 1,191 MMcf/d from 1,252 MMcf/d from the third quarter of 2011 and decreased by 5% from 1,255 MMcf/d for the second quarter of 2012. The decrease in natural gas production for the third quarter of 2012 from the comparable periods was primarily a result of expected production declines due to the allocation of capital to higher return crude oil projects, which continue to result in a strategic reduction of natural gas drilling activity. The Company shut in approximately 20 MMcf/d of natural gas production in 2012 and overall has shut in approximately 40 MMcf/d due to the decrease in natural gas prices. Natural gas production in the third quarter of 2012 slightly exceeded the Company–s previously issued guidance of 1,170 to 1,190 MMcf/d.
For 2012, annual production guidance is targeted to average between 452,000 and 460,000 bbl/d of crude oil and NGLs and between 1,222 and 1,229 MMcf/d of natural gas. Fourth quarter 2012 production guidance is targeted to average between 467,000 and 495,000 bbl/d of crude oil and NGLs and between 1,145 and 1,165 MMcf/d of natural gas.
North America – Exploration and Production
North America crude oil and NGLs production for the nine months ended September 30, 2012 increased 7% to average 318,384 bbl/d from 296,892 bbl/d for the nine months ended September 30, 2011. For the third quarter of 2012, crude oil and NGLs production increased 9% to average 332,895 bbl/d compared with 304,671 bbl/d for the third quarter of 2011 and increased 5% from 316,483 bbl/d for the second quarter of 2012. Increases in crude oil and NGLs production from comparable periods were primarily due to the impact of a strong heavy crude oil drilling program and the cyclic nature of the Company–s thermal operations. Production of crude oil and NGLs was at the upper end of the Company–s previously issued guidance of 322,000 bbl/d to 335,000 bbl/d for the third quarter of 2012. Fourth quarter 2012 production guidance is targeted to average between 350,000 and 365,000 bbl/d of crude oil and NGLs.
Natural gas production for the nine months ended September 30, 2012 averaged 1,226 MMcf/d and was comparable with the nine months ended September 30, 2011. Natural gas production decreased 5% to 1,169 MMcf/d for the third quarter of 2012 compared with 1,226 MMcf/d in the third quarter of 2011 and 1,230 MMcf/d in the second quarter of 2012. Natural gas production for the third quarter of 2012 decreased from the comparable periods primarily as a result of expected production declines due to the allocation of capital to higher return crude oil projects, which continue to result in a strategic reduction of natural gas drilling activity. The Company has reduced its drilling activities and shut in approximately 40 MMcf/d of natural gas production due to the decline in natural gas prices.
North America – Oil Sands Mining and Upgrading
Production averaged 87,084 bbl/d for the nine months ended September 30, 2012 compared with 19,365 bbl/d for the nine months ended September 30, 2011. For the third quarter of 2012, SCO production averaged 99,205 bbl/d compared with 50,354 bbl/d for the third quarter of 2011 and 115,823 bbl/d for the second quarter of 2012. Production for the three and nine months ended September 30, 2012 increased from the comparable periods in 2011 as production volumes in 2011 reflected the suspension of production due to the coker fire incident. Third quarter production in 2012 decreased from the second quarter as the Company operated at restricted rates for a portion of the third quarter to ensure safe, steady, reliable operations in anticipation of the proactive planned 12 day outage in the fourth quarter. Production of SCO remained within the Company–s previously issued guidance of 95,000 to 105,000 bbl/d for the third quarter of 2012.
Subsequent to September 30, 2012 the Company completed the 12 day planned maintenance outage followed by a return to full production. Full year production guidance for 2012 has been revised to 87,000 bbl/d to 89,000 bbl/d.
North Sea
North Sea crude oil production for the nine months ended September 30, 2012 decreased 35% to 20,054 bbl/d from 31,077 bbl/d for the nine months ended September 30, 2011. For the third quarter of 2012, North Sea crude oil production decreased 26% to 19,502 bbl/d from 26,350 bbl/d for the third quarter of 2011, and increased 11% from 17,619 bbl/d for the second quarter of 2012. The decrease in production volumes for the three and nine months ended September 30, 2012 from the comparable periods in 2011 was primarily due to temporary shut ins of the third-party operated pipeline to Sullom Voe for unplanned maintenance, which caused all Ninian and associated fields to be shut in, planned turnaround activity, the suspension of production at Banff/Kyle, and natural field declines due to curtailment of development activities in the North Sea as a result of corporate tax increases that were enacted in 2011. The increase in production volumes for the third quarter of 2012 from the second quarter of 2012 was due to the temporary reinstatement of the third-party operated pipeline to Sullom Voe, which was subsequently shut in again in late September 2012, and the timing of planned turnaround activity. In December 2011, the Banff Floating Production, Storage and Offloading Vessel (“FPSO”) and subsea infrastructure suffered storm damage. Operations at Banff/Kyle, with combined net production of approximately 3,500 bbl/d, were suspended and appropriate shut-down procedures were activated. The FPSO and associated floating storage unit have subsequently been removed from the field. The extent of the damage, including associated costs and related property damage, are not expected to be significant. The timing of returning to the field is currently being assessed.
Offshore Africa
Offshore Africa crude oil production decreased 15% to 19,618 bbl/d for the nine months ended September 30, 2012 from 23,105 bbl/d for the nine months ended September 30, 2011. Third quarter crude oil production averaged 17,566 bbl/d, decreasing 22% from 22,525 bbl/d for the third quarter of 2011 and decreasing 15% from 20,598 bbl/d in the second quarter of 2012. The decrease in production volumes from the comparable periods was due to natural field declines and the shut in of approximately 1,500 bbl/d of production at the Olowi field, Gabon as a result of a second failure in the midwater arch. The Company is currently assessing the operability of the midwater arch.
International Guidance
The Company–s North Sea and Offshore Africa third quarter 2012 crude oil and NGLs production was within the Company–s previously issued guidance of 34,000 to 40,000 bbl/d. Fourth quarter 2012 production guidance is targeted to average between 32,000 and 38,000 bbl/d of crude oil.
Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when title transfers to the customer and delivery has taken place. Revenue has not been recognized on crude oil volumes that were stored in various tanks, pipelines, or floating production, storage and offloading vessels, as follows:
OPERATING HIGHLIGHTS – EXPLORATION AND PRODUCTION
PRODUCT PRICES – EXPLORATION AND PRODUCTION
North America
North America realized crude oil prices decreased 2% to average $67.54 per bbl for the nine months ended September 30, 2012 from $69.21 per bbl for the nine months ended September 30, 2011. North America realized crude oil prices averaged $63.73 per bbl for the third quarter of 2012, a decrease of 6% compared with $67.81 per bbl for the third quarter of 2011 and a decrease of 2% compared with $65.10 per bbl for the second quarter of 2012. The decrease in prices for the three and nine months ended September 30, 2012 from the comparable periods in 2011 was primarily a result of the widening of the WCS Heavy Differential; partially offset by the fluctuations in the Canadian dollar relative to the US dollar. The Company continues to focus on its crude oil blending marketing strategy, and in the third quarter of 2012 contributed approximately 155,000 bbl/d of heavy crude oil blends to the WCS stream.
In the first quarter of 2011, the Company announced that it had entered into a partnership agreement with North West Upgrading Inc. to move forward with detailed engineering regarding the construction and operation of a bitumen upgrader and refinery (“the Project”) near Redwater, Alberta. In addition, the partnership has entered into processing agreements that target to process bitumen for the Company and the Government of Alberta under a 30 year fee-for-service tolling agreement under the Bitumen Royalty In Kind initiative. Subsequent to September 30, 2012, the Project was sanctioned by the Board of Directors of each partner of the North West Redwater Partnership (“Redwater”), and the associated target toll amounts were agreed to by Redwater, the Company and the Government of Alberta.
North America realized natural gas prices decreased 44% to average $2.09 per Mcf for the nine months ended September 30, 2012 from $3.73 per Mcf for the nine months ended September 30, 2011. North America realized natural gas prices decreased 41% to average $2.15 per Mcf for the third quarter of 2012 compared with $3.67 per Mcf in the third quarter of 2011, and increased 24% compared with $1.73 per Mcf for the second quarter of 2012. The decrease in natural gas prices for the three and nine months ended September 30, 2012 from the comparable periods in 2011 was primarily due to lower NYMEX and AECO benchmark pricing related to the impact of strong supply from US shale projects. The increase in natural gas prices for the third quarter of 2012 from the second quarter of 2012 was primarily due to higher NYMEX and AECO benchmark pricing related to a shift to higher utilization of gas fired electric generators and higher weather related gas demand resulting from warmer than normal summer temperatures.
Comparisons of the prices received in North America Exploration and Production by product type were as follows:
North Sea
North Sea realized crude oil prices increased 3% to average $111.38 per bbl for the nine months ended September 30, 2012 from $108.18 per bbl for the nine months ended September 30, 2011. Realized crude oil prices averaged $106.68 per bbl for the third quarter of 2012, a decrease of 2% from $109.28 per bbl for the third quarter of 2011, and a decrease 1% from $108.22 per bbl for the second quarter of 2012. The fluctuations in realized crude oil prices in the North Sea from the comparable periods were primarily the result of fluctuations in Brent benchmark pricing and the Canadian dollar, and the timing of liftings.
Offshore Africa
Offshore Africa realized crude oil prices increased 8% to average $115.19 per bbl for the nine months ended September 30, 2012 from $106.93 per bbl for the nine months ended September 30, 2011. Realized crude oil prices decreased 2% to average $112.59 per bbl for the third quarter of 2012 from $114.44 per bbl for the third quarter of 2011, and increased 6% from $106.30 per bbl for the second quarter of 2012. The fluctuations in realized crude oil prices in Offshore Africa from the comparable periods were primarily the result of fluctuations in Brent benchmark pricing and the Canadian dollar, and the timing of liftings.
ROYALTIES – EXPLORATION AND PRODUCTION
North America
North America crude oil and natural gas royalties for the nine months ended September 30, 2012 compared with the nine months ended September 30, 2011 reflected benchmark commodity prices.
Crude oil and NGLs royalties averaged approximately 18% of product sales for the third quarter of 2012 compared with 17% for the third quarter of 2011 and 13% for the second quarter of 2012. The increase in royalties from the second quarter of 2012 was the result of fluctuating pricing related to production from Oil Sands Royalty projects. Crude oil and NGLs royalties per bbl are anticipated to average 16% to 18% of product sales for 2012.
Natural gas royalties averaged approximately 1% of product sales for the second and third quarters of 2012 compared with 4% for the third quarter of 2011. The decrease in natural gas royalty rates from the third quarter of 2011 was due to lower realized natural gas prices. Natural gas royalties are anticipated to average 1% to 2% of product sales for 2012.
Offshore Africa
Under the terms of the various Production Sharing Contracts, royalty rates fluctuate based on realized commodity pricing, capital costs, the status of payouts, and the timing of liftings from each field.
Royalty rates as a percentage of product sales averaged approximately 32% for the third quarter of 2012 compared with 18% for the third quarter of 2011 and 26% for the second quarter of 2012. The increase in royalty rates from the comparable periods was due to higher crude oil prices during the year, adjustments to royalties on liftings, and the payout of the Baobab field in May 2011.
Offshore Africa royalty rates are anticipated to average 23% to 28% of product sales for 2012.
PRODUCTION EXPENSE – EXPLORATION AND PRODUCTION