CALGARY, ALBERTA–(Marketwired – Oct. 30, 2013) –
Unless otherwise noted, all financial figures are unaudited, presented in Canadian dollars (Cdn$), and have been prepared in accordance with International Financial Reporting Standards (IFRS), specifically International Accounting Standard (IAS) 34 Interim Financial Reporting as issued by the International Accounting Standards Board. Effective January 1, 2013, Suncor adopted new and amended accounting standards, described in the Other Items section of Suncor’s Management’s Discussion and Analysis dated Oct. 30, 2013 (the MD&A). Comparative figures presented in this news release pertaining to Suncor’s 2012 results have been restated in accordance with the respective transitional provisions of the new and amended standards. Production volumes are presented on a working interest basis, before royalties, unless noted otherwise. Certain financial measures referred to in this document (operating earnings, cash flow from operations, return on capital employed (ROCE) and Oil Sands cash operating costs) are not prescribed by Canadian generally accepted accounting principles (GAAP). References to Oil Sands operations exclude Suncor’s interest in Syncrude.
“This quarter’s results reflect a significant step forward in our drive to increase profitability,” said Steve Williams, president and chief executive officer. “We achieved record Oil Sands production in the quarter as a result of debottlenecking activities that unlocked production in our mining operations, increased our operational flexibility and added incremental barrels at a low cost.”
• Operating earnings of $1.426 billion ($0.95 per common share), including record operating earnings for the Oil Sands segment, and net earnings of $1.694 billion ($1.13 per common share).
• Cash flow from operations of $2.528 billion ($1.69 per common share).
• Record average quarterly production of 396,400 barrels per day (bbls/d) at Oil Sands operations and lower cash operating costs of $32.60 per barrel.
• Suncor completed the sale of a significant portion of its natural gas business in Western Canada for proceeds of $1 billion, before closing adjustments and other closing costs, resulting in an after-tax gain on sale of $130 million.
• On October 30, 2013, the Fort Hills oil sands mining project received sanction. The project is expected to provide Suncor with up to 73,000 bbls/d of bitumen, with first oil expected as early as the fourth quarter of 2017.
Suncor Energy Inc. recorded third quarter 2013 operating earnings of $1.426 billion ($0.95 per common share), compared to $1.292 billion ($0.84 per common share) for the third quarter of 2012. Strong operating earnings included a record for the Oil Sands segment which was driven by record production, strong reliability and favourable pricing for western Canadian crude oil. The integrated model enabled the company to capture the strength in inland pricing through its Oil Sands operations while continuing to realize incremental profit by obtaining global-based pricing through the company’s refining operations and vast logistics network.
Cash flow from operations was $2.528 billion ($1.69 per common share) for the third quarter of 2013, compared to $2.743 billion ($1.79 per common share) for the third quarter of 2012, and decreased due to incremental current income tax expense the company had anticipated for its Canadian operations, which was partially offset by the positive factors that impacted operating earnings. Net earnings were $1.694 billion ($1.13 per common share) for the third quarter of 2013, compared with net earnings of $1.544 billion ($1.01 per common share) for the third quarter of 2012, and were impacted by the same factors that affected operating earnings. Net earnings for the third quarter of 2013 included an after-tax gain of $130 million on the sale of a significant portion of the company’s natural gas business in Western Canada. The sale is consistent with Suncor’s strategy to focus on a core portfolio of high return assets. Net earnings for the third quarter of 2013 also included an after-tax foreign exchange gain on the revaluation of U.S. dollar denominated debt of $138 million, compared to $252 million in the prior year quarter.
ROCE (excluding major projects in progress) for the twelve months ended September 30, 2013 was 8.6%, compared to 12.4% for the twelve months ended September 30, 2012. ROCE for the twelve months ended September 30, 2013 was reduced by 4.3% due to an after-tax impairment charge of $1.487 billion relating to the Voyageur upgrader project recorded in the fourth quarter of 2012, in addition to an after-tax charge of $127 million recorded in the first quarter of 2013 as a result of not proceeding with the project.
Suncor’s total upstream production rose to an average of 595,000 boe/d in the third quarter of 2013 from 535,300 boe/d in the third quarter of 2012.
Production volumes for Oil Sands operations increased 16% to a record quarterly average of 396,400 bbls/d in the third quarter of 2013, compared to 341,300 bbls/d in the third quarter of 2012. Factors contributing to the step change in production included the ongoing ramp up of production at Firebag, successful execution of debottlenecking projects, solid performance in mining and strong upgrading reliability. The company commissioned its hot bitumen assets in the quarter, which are comprised of an insulated pipeline from Firebag to Suncor’s Athabasca terminal, bitumen cooling and blending facilities, and capacity to import third-party diluents. This new infrastructure and logistics capability has increased the takeaway capacity of bitumen and unlocked production in mining.
Production for Oil Sands operations was reduced in September as a result of planned maintenance at the Upgrader 2 vacuum tower and related units, which was successfully completed in October. This marks the completion of major planned maintenance activities in Oil Sands for the year and sets the foundation for a strong fourth quarter.
Sales volumes for Oil Sands operations increased to an average of 371,800 bbls/d for the third quarter of 2013, compared to 345,400 bbls/d in the prior year quarter, as a result of increased production, partially offset by a build in inventory. Inventories were replenished following the Upgrader 1 turnaround completed in the second quarter of 2013. In addition, the company’s average inventory levels rose due to new infrastructure added to the company’s storage and logistics network in support of the growth in production.
Cash operating costs per barrel for Oil Sands operations in the third quarter of 2013 decreased to an average of $32.60 compared to $33.35 in the third quarter of 2012, reflecting higher production volumes, slightly offset by marginally higher cash operating costs. Cash operating costs increased over the prior year quarter due to incremental costs associated with larger operations, including Firebag Stage 4, higher maintenance activities in mining, and higher natural gas costs, partially offset by the net benefit of increased power sales.
“We demonstrated improved reliability across our operations this quarter, underscoring our commitment to operational excellence,” said Williams. “In Oil Sands, strong upgrader performance contributed to a monthly production record of 433,000 bbls/d in August. In the downstream, we saw record quarterly refinery utilizations rates, reinforcing our position as a leader in the refining industry in North America.”
Suncor’s share of Syncrude production decreased to an average of 27,200 bbls/d in the third quarter of 2013 from 37,600 bbls/d in the third quarter of 2012, due primarily to planned maintenance performed on one of three cokers and the LC Finer. The maintenance was completed in the quarter and units returned to production in late August.
The Exploration and Production segment contributed an average of 171,400 boe/d of production in the third quarter of 2013, compared to 156,400 boe/d in the same period of 2012, primarily due to significantly less planned maintenance at all East Coast Canada assets in the quarter. Production in the third quarter of 2013 was impacted by the shut in of production in Libya in response to political unrest and related labour disputes that resulted in the closure of export terminal operations at certain Libyan seaports. Suncor has not lifted production in Libya since May 2013, although field activities have continued throughout the quarter. Suncor continues to monitor the situation as the country continues its difficult transition to a more stable environment.
Planned maintenance at White Rose and Buzzard was successfully completed in the third quarter of 2013. In late September, the company commenced an eleven-week off-station maintenance event at the Terra Nova facility to complete routine maintenance, repair a damaged mooring chain and perform preventive maintenance on the remaining eight chains. There will be no production from Terra Nova during this maintenance period.
The Refining and Marketing segment continued to demonstrate strong reliability with refinery utilization of 98% in the third quarter of 2013. Total refinery crude throughput reached a record quarterly average of 448,800 bbls/d during the third quarter of 2013, compared to 441,400 bbls/d in the third quarter of 2012.
Suncor continued to deliver value to shareholders through $299 million in dividends ($0.20 per common share) and share repurchases of $426 million in the third quarter of 2013.
Investing in Integration and Market Access
Suncor’s integrated model has enabled the company to capture Brent-based pricing on the majority of its Oil Sands production through its refining operations and vast logistics network. As Suncor’s upstream production continues to grow, enhancing integration within the company’s operations and securing market access are key to operational flexibility and maximizing profitability.
Suncor continues activities to secure market access into Canadian and U.S. coastal markets, positioning the company to capture global prices on both its current production and future growth. By early 2014, the company expects to increase its heavy crude shipping capacity to the U.S. Gulf Coast through the Keystone South pipeline, which is intended to increase logistics and marketing flexibility. Suncor expects to meet linefill requirements on the pipeline in the fourth quarter of 2013. During the quarter, the company also entered into firm commitments for rail cars and terminalling services in support of its market access strategy to transport inland crudes to its Montreal refinery and to coastal markets. This strategy includes a rail offloading facility in Montreal, which is expected to take delivery of crude starting in the fourth quarter of 2013.
Oil Sands Operations
Investing in reliable and sustainable operations remains a priority. Following the seven-week planned turnaround of Upgrader 1 in the second quarter of 2013, Suncor executed the last planned maintenance event of the year at its Upgrader 2 vacuum tower and related units, which was successfully completed in October.
Suncor continues to advance projects that are focused on discrete growth through low-cost investments to optimize existing assets, including debottlenecking and expansion projects. The company began to realize the benefits of these activities through the commissioning of the hot bitumen infrastructure, which unlocked production in mining in the third quarter of 2013. The company continued to progress a debottleneck of the MacKay River facility, which is intended to increase production capacity by approximately 20% over the next two years for a total capacity of 38,000 bbls/d. Suncor also continues to work towards a 2014 sanction decision of the MacKay River expansion project, which is targeted to have an initial design capacity of approximately 20,000 bbls/d and first oil in 2017.
In addition, the final two of four storage tanks in Hardisty, Alberta, were commissioned to support growing Oil Sands production.
Oil Sands Ventures
On October 30, 2013, Suncor announced that the project co-owners voted unanimously to proceed with the Fort Hills oil sands mining project. Suncor has a 40.8% interest and is the developer and operator of the project. The project has approximately 3.3 billion barrels of best estimate contingent resources and is scheduled to produce first oil as early as the fourth quarter of 2017 and achieve 90% of its planned production capacity of 180,000 bbls/d within twelve months.
The total post-sanction capital investment in Fort Hills is estimated at approximately $13.5 billion ($5.5 billion net to Suncor), with total project costs estimated to be at a capital intensity of approximately $84,000 per flowing barrel of bitumen.
“The Fort Hills project is aligned with our strategic objective to only invest in projects that will provide the company with long-term profitable growth. With a mine life in excess of 50 years, this project will provide a stable source of cash flow over the long term,” said Williams. “We are excited by the addition of this project to our core portfolio of assets and the potential synergies we can achieve with our existing operated assets.”
Suncor and the co-owners of the Joslyn mining project continue to focus on design engineering and regulatory work, and plan to provide an update on the targeted timing for a project sanction decision when available.
Exploration and Production
On April 15, 2013, Suncor announced it had reached an agreement to sell a significant portion of its natural gas business in Western Canada, with an effective date of January 1, 2013. The transaction closed on September 26, 2013 for proceeds of $1 billion, before closing adjustments and other closing costs, resulting in an after-tax gain on sale of $130 million. Production from these assets was approximately 41,000 boe/d in the third quarter of 2013, of which 90% was natural gas. Net earnings and cash flow from operations for the third quarter of 2013 from these assets were approximately $17 million and $28 million, respectively. Excluded from the sale was the majority of Suncor’s unconventional natural gas properties in the Kobes region of British Columbia and unconventional oil properties in the Wilson Creek area of central Alberta.
The Golden Eagle project continued to progress in the quarter with the installation of the second jacket and the wellhead deck. With drilling activities expected to commence by early 2014, the project remains on target to achieve first oil in late 2014 or early 2015. Detailed engineering and construction of the gravity-based structure and topsides continued for the Hebron project in the third quarter of 2013; the project is expected to achieve first oil in 2017. Subsea installation began for the Hibernia Southern Extension Unit and is expected to be completed in the fourth quarter of 2013. The project is expected to increase overall production from the Hibernia field starting in 2015. Installation activities, detailed engineering and procurement activities continued for the remainder of the South White Rose Extension project. Subsea equipment for this project is being installed in two phases over 2013 and 2014. First oil is expected in the fourth quarter of 2014.
Operating Earnings Reconciliation(1)
|Three months ended
|Nine months ended
|Net earnings as reported||1 694||1 544||3 468||3 314|
|Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt||(138||)||(252||)||262||(237||)|
|Gain on significant disposals(2)||(130||)||–||(130||)||–|
|Net impact of not proceeding with the Voyageur upgrader project(3)||–||–||127||–|
|Impairments and write-offs(4)||–||–||–||694|
|Impact of income tax rate adjustments on deferred income taxes(5)||–||–||–||88|
|Operating earnings||1 426||1 292||3 727||3 859|
|(1)||Operating earnings is a non-GAAP financial measure. All reconciling items are presented on an after-tax basis. See the Non-GAAP Financial Measures Advisory section of the MD&A.|
|(2)||Represents the after-tax gain on sale from the disposition of a significant portion of the company’s natural gas business in Western Canada.|
|(3)||Represents the expected cost of not proceeding with the project, including costs related to decommissioning and restoration of the Voyageur site, and contract cancellations.|
|(4)||Reflects the impairment and write-off of assets in Syria.|
|(5)||Represents the elimination of the planned general corporate income tax rate reduction in the Province of Ontario.|
Suncor has revised its corporate guidance that it previously issued on July 31, 2013. The key changes to the company’s production guidance include:
• The decrease in outlook for International reflects the shut in of production in Libya due to political unrest and labour disputes.
• The decrease in outlook for Syncrude reflects the impact of unplanned outages in upgrading, and the extension of planned maintenance for one coker unit and the LC Finer in the year-to-date period.
• The decrease in outlook for North America Onshore reflects the sale of a significant portion of the company’s natural gas business in Western Canada, which closed on September 26, 2013. The company expects approximately 4,000 boe/d – 5,000 boe/d of production from its remaining properties in North America Onshore.
|2013 Full Year Outlook
July 31, 2013
|2013 Full Year Outlook
Revised October 30, 2013
|Actual Nine Months Ended
September 30, 2013
|International (boe/d)||90 000 – 96 000||72 000 – 79 000||81 800|
|Syncrude (bbls/d)||34 000 – 38 000||32 000 – 33 000||30 400|
|North America Onshore (boe/d)||41 000 – 46 000||36 000 – 38 000||48 400|
Total production guidance has been reduced to 545,000 boe/d – 590,000 boe/d from 570,000 boe/d – 620,000 boe/d, as a result of the changes described above.
Suncor has also reduced its corporate guidance for capital expenditures by $300 million to $6.7 billion. The decrease in outlook for capital expenditures reflects:
• Project prioritization that resulted in the deferral of spending and lower cost estimates from scope optimization in Exploration and Production.
• Reductions to the unallocated discretionary growth capital pool in Corporate, Energy Trading and Eliminations.
|2013 Full Year Outlook
July 31, 2013
|2013 Full Year Outlook
Revised October 30, 2013
|Oil Sands||2 860||1 305||4 165||2 845||1 300||4 145|
|Oil Sands operations||2 470||535||3 005||2 455||460||2 915|
|Oil Sands Ventures||390||770||1 160||390||840||1 230|
|Exploration and Production||215||1 405||1 620||165||1 335||1 500|
|Refining and Marketing||700||150||850||750||165||915|
|Corporate, Energy Trading and Eliminations||95||270||365||95||45||140|
|3 870||3 130||7 000||3 855||2 845||6 700|
|(1)||Capital expenditures exclude capitalized interest of between $350 million and $450 million.|
|(2)||For definitions of growth and sustaining capital expenditures, see the Capital Investment Update section of the MD&A.|
Certain sales assumptions were also revised. For further details regarding Suncor’s 2013 revised corporate guidance, see www.suncor.com/guidance.
Advisories, Assumptions and Risk Factors
The Strategy Update and Corporate Guidance discussions above contain forward-looking information, including the information identified in the Legal Advisory Forward-Looking Information section of this news release. Forward-looking information is subject to a number of risks and uncertainties, many of which are beyond Suncor’s control, including those outlined below and in the Forward-Looking Information section of the MD&A.
Capital intensity per flowing barrel of bitumen is calculated by dividing the anticipated project costs of the Fort Hills project by the anticipated production capacity of the project. This measure is included because management uses the information to analyze capital efficiency. Capital intensity per flowing barrel of bitumen does not have any standard meaning and therefore is unlikely to be comparable to similar measures presented by other companies. Readers are cautioned not to place undue reliance on this measure.
Suncor’s corporate guidance is based on the following commodity price assumptions: West Texas Intermediate crude oil at Cushing of US$93.00 per barrel (bbl); Brent, Sullom Voe of US$100.00/bbl; and Western Canadian Select at Hardisty of US$73.00/bbl. In addition, the guidance is based on the assumption of a natural gas price (AECO – C Spot) of Cdn$3.35/gigajoule and an exchange rate (US$/Cdn$) of $0.96. Assumptions for the Oil Sands and Syncrude 2013 production outlook include those relating to reliability and operational efficiency initiatives that the company expects will minimize unplanned maintenance for the remainder of 2013. Assumptions for the Exploration and Production 2013 production outlook include those relating to reservoir performance, drilling results and facility reliability. Factors that could potentially impact Suncor’s 2013 corporate guidance include, but are not limited to:
• Bitumen supply. Bitumen supply may be dependent on unplanned maintenance of mine equipment and extraction plants, bitumen ore grade quality, tailings storage and in situ reservoir performance.
• Third-party pipelines. Production estimates could be negatively impacted by third-party pipeline disruptions that may result in the apportionment of capacity or pipeline shutdowns, which would affect the company’s ability to market its crude oil.
• Performance of recently commissioned facilities or well pads. Production rates while new equipment is being brought into service are difficult to predict and can be impacted by unplanned maintenance. Sweet synthetic crude oil production levels from Oil Sands are dependent on the successful operation of hydrogen plants and hydrotreating units. Bitumen production levels are dependent on the successful ramp up of Firebag Stage 4.
• Unplanned maintenance. Production estimates could be negatively impacted if unplanned work is required at any of our mining, extraction, upgrading, in situ processing, refining, natural gas processing, pipeline, or offshore assets.
• Planned maintenance events. Production estimates, including production mix, could be negatively impacted if planned maintenance events are affected by unexpected events. The successful execution of maintenance and start-up of operations for offshore assets, in particular, may be impacted by harsh weather conditions, particularly in the winter season.
• Commodity prices. Declines in commodity prices may alter our production outlook and/or reduce our capital expenditure plans.
• Foreign operations. Suncor’s foreign operations and related assets are subject to a number of political, economic and socio-economic risks.
Non-GAAP Financial Measures
Operating earnings and Oil Sands cash operating costs are defined in the Non-GAAP Financial Measures Advisory section of the MD&A and reconciled to GAAP measures in the Segment Results and Analysis – Oil Sands section of the MD&A. Cash flow from operations and ROCE are defined and reconciled to GAAP measures in the Non-GAAP Financial Measures Advisory section of the MD&A.
These non-GAAP financial measures are included because management uses this information to
analyze operating performance, leverage and liquidity. These non-GAAP measures do not have any standardized meaning and therefore are unlikely to be comparable to similar measures presented by other companies and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP.
Legal Advisory – Forward-Looking Information
This news release contains certain forward-looking information and forward-looking statements (collectively referred to herein as “forward-looking statements”) within the meaning of applicable Canadian and U.S. securities laws. Forward-looking statements are based on Suncor’s current expectations, estimates, projections and assumptions that were made by the company in light of its information available at the time the statement was made and consider Suncor’s experience and its perception of historical trends, including expectations and assumptions concerning: the accuracy of reserves and resources estimates; commodity prices and interest and foreign exchange rates; capital efficiencies and cost savings; applicable royalty rates and tax laws; future production rates; the sufficiency of budgeted capital expenditures in carrying out planned activities; the availability and cost of labour and services; and the receipt, in a timely manner, of regulatory and third-party approvals. In addition, all other statements and information about Suncor’s strategy for growth, expected and future expenditures or investment decisions, commodity prices, costs, schedules, production volumes, operating and financial results and the expected impact of future commitments are forward-looking statements. Some of the forward-looking statements and information may be identified by words like “expects”, “anticipates”, “will”, “estimates”, “plans”, “scheduled”, “intends”, “believes”, “projects”, “indicates”, “could”, “focus”, “vision”, “goal”, “outlook”, “proposed”, “target”, “objective”, “continue”, “should”, “may” and similar expressions.
Forward-looking statements in this news release include references to: the company’s plans to work towards a 2014 sanction decision of the MacKay River expansion project, which is targeted to have an initial design capacity of approximately 20,000 bbls/d and first oil in 2017; the estimate that total post-sanction capital investment in Fort Hills is estimated at approximately $13.5 billion ($5.5 billion net to Suncor) and that total project costs for the Fort Hills project are estimated to be at a capital intensity of approximately $84,000 per flowing barrel of bitumen; Suncor’s expectations about production volumes and the performance of its existing assets; the anticipated duration and impact of planned maintenance events, including the company’s expectation that all planned maintenance events for Oil Sands are complete for the year; Suncor’s expectations about capital expenditures, and growth and other projects, including the company’s capital allocation plans; the company’s plans to increase its heavy crude shipping capacity to the U.S. Gulf Coast through its capacity on the Keystone South pipeline; resulting in additional logistics and marketing flexibility; the company’s plans to meet line fill requirements on the Keystone South pipeline in the fourth quarter of 2013; the expectation that the rail offloading facility in Montreal will take delivery of crude starting in the fourth quarter of 2013; the debottlenecking project at the MacKay River facilities is expected to increase production capacity by approximately 20% over the next two years for a total capacity of 38,000 bbls/d; the expectation that the Fort Hills project will produce first oil as early as the fourth quarter of 2017, achieve 90% of its planned production capacity of 180,000 bbls/d (73,000 bbls/d net to Suncor) within twelve months, have an expected mine life in excess of 50 years at the current planned production rate (which assumes that all of the estimated contingent resources are developed), and that Suncor’s portion of the post-sanction capital investment in Fort Hills is estimated at approximately $5.5 billion; the company’s plans to continue to focus on design engineering and regulatory work and to provide an update on the targeted timing for a sanction decision for the Joslyn mining project when available; the design and construction of new well pads at Firebag and MacKay River are expected to maintain existing production levels in future years; drilling activities on Golden Eagle project are expected to commence by early 2014, and the project is expected to achieve first oil in late 2014 or early 2015; subsea installation for the Hibernia Southern Extension Unit is expected to be completed in the fourth quarter of 2013. The project is expected to increase the overall production from the Hibernia field starting in 2015; subsea equipment for the South White Rose Extension project is expected to be installed in two phases over 2013 and 2014. First oil is expected in the fourth quarter of 2014; and that the Hebron project is expected to achieve first oil in 2017.
Forward-looking statements and information are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Suncor’s actual results may differ materially from those expressed or implied by its forward-looking statements, so readers are cautioned not to place undue reliance on them.
Additional risks, uncertainties and other factors that could influence financial and operating performance of all of Suncor’s operating segments and activities include, but are not limited to, changes in general economic, market and business conditions, such as commodity prices, interest rates and currency exchange rates; fluctuations in supply and demand for Suncor’s products; the successful and timely implementation of capital projects, including growth projects and regulatory projects; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; labour and material shortages; actions by government authorities, including the imposition or reassessment of taxes or changes to fees and royalties, and changes in environmental and other regulations; the ability and willingness of parties with whom we have material relationships to perform their obligations to us; the occurrence of unexpected events such as fires, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor; the potential for security breaches of Suncor’s information systems by computer hackers or cyber terrorists, and the unavailability or failure of such systems to perform as anticipated as a result of such breaches; our ability to find new oil and gas reserves that can be developed economically; the accuracy of Suncor’s reserves, resources and future production estimates; market instability affecting Suncor’s ability to borrow in the capital debt markets at acceptable rates; maintaining an optimal debt to cash flow ratio; the success of the company’s risk management activities using derivatives and other financial instruments; the cost of compliance with current and future environmental laws; risks and uncertainties associated with closing a transaction for the purchase or sale of an oil and gas property, including estimates of the final consideration to be paid or received, the ability of counterparties to comply with their obligations in a timely manner and the receipt of any required regulatory or other third-party approvals outside of Suncor’s control that are customary to transactions of this nature; and the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement or conception of the detailed engineering that is needed to reduce the margin of error and increase the level of accuracy. The foregoing important factors are not exhaustive.
The MD&A and Suncor’s Annual Information Form (the “2012 AIF”) and Form 40-F, each dated March 1, 2013, Annual Report to Shareholders and other documents it files from time to time with securities regulatory authorities describe the risks, uncertainties, material assumptions and other factors that could influence actual results and such factors are incorporated herein by reference. Copies of these documents are available without charge from Suncor at 150 6th Avenue S.W., Calgary, Alberta T2P 3E3, by calling 1-800-558-9071, or by email request to firstname.lastname@example.org or by referring to the company’s profile on SEDAR at www.sedar.com or EDGAR at www.sec.gov. Except as required by applicable securities laws, Suncor disclaims any intention or obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
Legal Advisory – Resources
Suncor’s operating working interest before deduction of royalties, and without including any royalty interests of Suncor, in the approximately 3.3 billion barrels of contingent resources associated with the Fort Hills project in Alberta is approximately 1.35 billion barrels of bitumen. In its 2012 AIF and Form 40-F, Suncor disclosed that the reclassification of the contingent resources, which have an effective date of December 31, 2012, for the Fort Hills project was largely contingent upon an assessment that development would be sanctioned and commence within a reasonable time frame. Since the date of its 2012 AIF, the respective co-owners of the Fort Hills project have sanctioned the project. Given the foregoing, these resources, or a portion thereof, may in the future be re-classified as reserves. Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. There is no certainty that it will be commercially viable to produce the contingent resources. There is no certainty as to timing of the development of the resources. The contingent resource estimates are considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. The best estimate of potentially recoverable volumes is prepared independent of the risks associated with achieving commercial production. There are numerous uncertainties inherent in estimating quantities and quality of these contingent resources, including many factors beyond our control. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or lack of infrastructure or markets. For more information on contingent resources, please see Suncor’s 2012 AIF and Form 40-F.
Legal Advisory – BOEs
Certain natural gas volumes have been converted to barrels of oil equivalent (boe) on the basis of one barrel to six thousand cubic feet. Any figure presented in boe may be misleading, particularly if used in isolation. A conversion ratio of one bbl of crude oil or natural gas liquids to six thousand cubic feet of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
Suncor Energy is Canada’s leading integrated energy company. Suncor’s operations include oil sands development and upgrading, conventional and offshore oil and gas production, petroleum refining, and product marketing under the Petro-Canada brand. While working to responsibly develop petroleum resources, Suncor is also developing a growing renewable energy portfolio. Suncor’s common shares (symbol: SU) are listed on the Toronto and New York stock exchanges.