DOCSLIB.ORG

Suncor Q3 2020 Investor Relations Supplemental Information Package

Total Page：16

File Type：pdf, Size：1020Kb

Download full-text PDF Read full-text
Suncor Q3 2020 Investor Relations Supplemental Information Package SUNCOR ENERGY Investor Information SUPPLEMENTAL Published October 28, 2020 SUNCOR ENERGY Table of Contents 1. Energy Sources 2. Processing, Infrastructure & Logistics 3. Consumer Channels 4. Sustainability 5. Technology Development 6. Integrated Model Calculation 7. Glossary SUNCOR ENERGY 2 SUNCOR ENERGY EnergyAppendix Sources 3 202003- 038 Oil Sands Energy Sources *All values net to Suncor In Situ Mining Firebag Base Plant 215,000 bpd capacity 350,000 bpd capacity Suncor WI 100% Suncor WI 100% 2,603 mmbbls 2P reserves1 1,350 mmbbls 2P reserves1 Note: Millennium and North Steepank Mines do not supply full 350,000 bpd of capacity as significant in-situ volumes are sent through Base Plant MacKay River Syncrude 38,000 bpd capacity Syncrude operated Suncor WI 100% 205,600 bpd net coking capacity 501 mmbbls 2P reserves1 Suncor WI 58.74% 1,217 mmbbls 2P reserves1 Future opportunities Fort Hills ES-SAGD Firebag Expansion Suncor operated Lewis (SU WI 100%) 105,000 bpd net capacity Meadow Creek (SU WI 75%) Suncor WI 54.11% 1,365 mmbbls 2P reserves1 First oil achieved in January 2018 SUNCOR ENERGY 1 See Slide Notes and Advisories. 4 1 Regional synergy opportunities for existing assets Crude logistics Upgrader feedstock optionality from multiple oil sands assets Crude feedstock optionality for Edmonton refinery Supply chain Sparing, warehousing & supply chain management Consolidation of regional contracts (lodging, busing, flights, etc.) Operational optimizations Unplanned outage impact mitigations In Situ Turnaround planning optimization Process and technology sharing 100% WI Joint ownership Base mine upgrader and terminal U Syncrude upgrader Assets and resource developments C In situ central processing facility Lease development and asset utilization optimization P Fort Hills primary/secondary extraction Pipelines SUNCOR ENERGY 1 See Slide Notes and Advisories 5 Long life, low decline reserves base 1 Typical attributes of North American oil plays Initial Decline Sustaining Operating Reservoir Recovery 2 3 Illustrative annual FFO profiles capital rate costs cost risk factor Mining High Very low Low Medium Very low Very high ~85% of Suncor’s 2020 production guidance In Situ Medium Low Low Low Low High Offshore ~15% of Suncor’s 2020 High Medium Medium Very low Medium Medium production guidance Tight Oil Low Very high High Medium High Low 50 Years Beneficial attribute Challenging attribute SUNCOR ENERGY 1, 2, 3 See Slide Notes and Advisories 6 Offshore with >370 million barrels of 2P reserves 1 East Coast Canada North Sea Hibernia ExxonMobil operated Buzzard (UK) Suncor working interest 20% CNOOC Petroleum Europe Limited operated 61 mmboe 2P reserves1 (Suncor WI) Suncor working interest 29.9% 1 2019 avg net production: 20.1 mbbls/d 63 mmboe 2P reserves (Suncor WI) 2019 avg net production: 31.9 mboe/d Hebron ExxonMobil operated Suncor working interest 21.0% 138 mmboe 2P reserves1 (Suncor WI) Golden Eagle (UK) 2019 avg net production: 23.5 mbbls/d CNOOC Petroleum Europe Limited operated Suncor working interest 26.7% 10 mmboe 2P reserves1 (Suncor WI) 2019 avg net production: 9.0 mboe/d Terra Nova Suncor Energy operated Suncor working interest 37.7% 25 mmboe 2P reserves1 (Suncor WI) Oda (Norway) 2019 avg net production: 11.6 mbbls/d Spirit Energy operated3 Suncor working interest 30% 7 mmboe 2P reserves1 (Suncor WI) White Rose First oil achieved March 2019 Husky Energy operated 2019 avg net production: 3.7 mboe/d Suncor working interest 27.5%2 Note: Q4 2019 avg net production: 7.8 mboe/d 54 mmboe 2P reserves1 (Suncor WI) 2019 avg net production: 4.7 mbbls/d SUNCOR ENERGY 1, 2, 3 See Slide Notes and Advisories 7 E&P – Investing in high value, low risk projects Recent performance Sanctioned projects1 mboe/d Fenja (Norway) 120 • 17.5% working interest 100 • 6 mbbls/d anticipated net peak production Hebron 80 White Rose Buzzard Phase 2 (UK) Hibernia 60 Terra Nova • 29.9% working interest 40 Golden Eagle • Production anticipated to offset natural declines Buzzard 20 4 West White Rose Project (ECC ) 0 2012 2013 2014 2015 2016 2017 2018 2019 • ~26% working interest • 20 mbbls/d anticipated net peak production 112 109 99 4 $billions Terra Nova Asset Life Extension (ECC ) 2.5 • 37.7% working interest 71 64 54 Brent • Extend asset life by approximately a decade 2.0 52 44 ($US/bbl) • Expect to produce additional 30 million barrels (Suncor WI) 1.5 FFO2 Free funds flow3 Capital spend 1.0 Future opportunities 0.5 • Rosebank-UK (40% Suncor WI) - • Near field developments including subsea 2012 2013 2014 2015 2016 2017 2018 2019 tie-backs, field extensions and infill drilling SUNCOR ENERGY 1, 2, 3, 4 See Slide Notes and Advisories 8 Power Generation Generating power for internal use & sale to the grid, including EV applications; currently 5th largest power producer in Alberta. 2,400 MW 1,400 MW 1 CURRENT CURRENT + SANCTIONED PROJECTS Cogen: 96%; Renewables: 4% (online by YE 2025) Cogen: 89%; Renewables: 11% MW Working interest nameplate capacity Net capacity for grid export Net internal consumption SUNCOR ENERGY 1 See Slide Notes and Advisories. 9 SUNCOR ENERGY Processing,Appendix Infrastructure & Logistics 10 202003- 038 Operations & Consumer Network 29 year Oil Sands Reserve Life Index1 ~25 mmbbl storage Western Canada ~1,850 PetroCanada sites2 ~15 mmbbl storage Eastern Canada Only refinery in Colorado ~10 mmbbl storage Central US & Gulf Coast OIL & REFINED PRODUCT STORAGE (SUNCOR OPERATED) SUNCOR ENERGY 1, 2 See Slide Notes & Advisories 11 Upgrading Upgrading processes heavy bitumen into a lighter, higher value product with a density Upgrading Process similar to that of WTI. LOW Once upgraded, the product can flow on a VALUE Mined & In-Situ Bitumen pipeline without the addition of diluent. HEAVY OIL (10° API) Total Suncor Net Upgrading Capacity: ~555 kbpd1 Coking, hydroconversion, • Base Plant ~15 – 20% yield loss thermal cracking &/or through upgrading process – 2 Upgrading Units hydrocracking • U1: 110 kbpd • U2: 240 kbpd – Produces sour & sweet SCO & diesel HIGH Sour Synthetic Crude Oil Optional: Hydrotreating (remove sulfur) • Syncrude (Gross values below – Suncor WI 58.74%) VALUE (30 - 35° API) LIGHT – 3 Upgrading Units OIL • U1: 100 kbpd • U2: 100 kbpd • U3: 150 kbpd Refinery Sweet Synthetic Crude Oil – Produces sweet SCO (30 - 35° API) • Edmonton Refinery – 30 kbpd coking capacity SUNCOR ENERGY 1 See Slide Notes & Advisories 12 Suncor’s proven oil sands reliability journey Suncor Base Plant upgrader reliability Multi-year journey to reach >90% reliability 1 2 91% 90% 91% 90% 90% 83% 81% 79% Suncor began focusing on upgrader reliability initiatives in 2011 Firebag to Base Mine Culture – Operational excellence mindset interconnect Process – Integrated maintenance strategy/approach pipeline fully operational Infrastructure – Asset integration between Firebag and Base Plant 2012 2013 2014 2015 2016 2017 2018 2019 Syncrude plant reliability In 2019, Syncrude achieved 2nd best A similar multi year journey targeting >90% reliability3 annual production in asset’s history with 85% utilization4 2016/17 2018/19 2020/21 (Target >90% reliability) Collaboration Culture Infrastructure Suncor’s active involvement in 31 technical/management Two bi-directional pipelines connecting Syncrude & Suncor’s base mine Syncrude’s reliability secondees from Suncor sharing Better utilization of existing assets: improvement plan operational discipline learnings • Normal operations - Transfer of sour synthetic and bitumen between assets • Planned and unplanned outages - Asset and production optimizations Sharing technical & reliability Process synergies best practices and support to Leveraging service & materials Construction completed, anticipated sanctioning in Q4 2020 improve productivity, reliability economies of scale and reduce costs Maintenance planning & execution coordination SUNCOR ENERGY 1, 2, 3, 4 See Slide Notes & Advisories 13 Market Access Suncor has made strategic investments in refineries and current/proposed logistics infrastructure to mitigate Alberta egress limitations & market disconnects Fort McMurray ~750 Alberta egress bottleneck does not impact the ability to move Suncor barrels1 142 Edmonton Hardisty Enbridge Line 3 Potential Markets Regina Central & Eastern Vancouver Cromer Canada, US Midwest & Gulf Coast 137 Montreal TMEP Potential Superior Markets Asia & California 85 Sarnia Steele City Chicago 98 Commerce Patoka City San Francisco Cushing Los Angeles KXL Potential Markets Pipelines 2 Heavy oil refineries (current and forecasted gross capacity ) along the Gulf Coast Feeder lines 2 Houston/Texas City Trans Mountain Pipeline, TMPL (300 mbpd) Suncor refinery capacity mbpd Trans Mountain Expansion , TMEP – Proposed3 (+590 mbpd)2 Industry approximate rail Express, Platte and Rocky Mountain (280 mbpd)2 mbpd loading capacity in TransCanada Keystone (590 mbpd)2 AB/SK TransCanada Keystone XL – Proposed3 (+830 mbpd) 2 Enbridge Mainline (2,600 mbpd)2 Enbridge Line 3 – Proposed3 (+370 mbpd) 2 Enbridge Line 9 (300 mbpd)2 Flanagan South Pipeline (585 mbpd)2 SUNCOR ENERGY 1, 2, 3 See Slide Notes & Advisories Marine opportunities 14 SUNCOR ENERGY ConsumerAppendix Channels 15 202003- 038 Refined Product Markets ~540 mbpd Product sales in 1 2019 Edmonton refinery services region from BC to Ontario Montreal and 20% Sarnia have a local market Canadian reach over 22mm Export consumer fuel people5 capability 2 market to US Pacific NW ~300 Wholesale Cardlock Locations3 Commerce City’ s asphalt Commerce City is market only refinery in stretches into Colorado & largest
Load more

Recommended publications
  • 2015 Annual Report Mission
    2015 annual report Mission Our mission is to facilitate innovation, collaborative research and technology development, demonstration and deployment for a responsible Canadian hydrocarbon energy industry. 2 Vision Our vision is to help Canada become a global hydrocarbon energy technology leader. PTAC Technology Areas Manage Environmental Impacts • Air Quality • Alternative Energy Improve Oil and Gas Recovery • Ecological • CO2 Enhanced Hydrocarbon Recovery • Emission Reduction / Eco-Efficiency • Coalbed Methane, Shale Gas, Tight Gas, Gas Hydrates, • Energy Efficiency and other Unconventional Gas • Resource Access • Conventional Heavy Oil, Cold Heavy Oil Production with • Soil and Groundwater Sands • Water • Conventional Oil and Gas Recovery • Wellsite Abandonment • Development of Arctic Resources • Development of Remote Resources Additional PTAC Technical Areas • Enhanced Heavy Oil Recovery • e-Business • Enhanced Oil and Gas Recovery • Genomics • Enhanced Oil Sands Recovery • Geomatics • Emerging Technologies to Recover Oil Sands from Deposits • Geosciences with Existing Zero Recovery • Health and Safety • Tight Oil, Shale Oil, and other Unconventional Oil • Instrumentation/Measurement • Nano Technology Reduce Capital, Operating, and G&A Costs • Operations • Automation • Photonics • Capital Cost Optimization • Production Engineering • Cost Reduction Using Emerging Drilling and Completion • Remote Sensing Technologies • Reservoir Engineering • Cost Reduction Using Surface Facilities • Security • Eco-Efficiency and Energy Efficiencyechnologies
    [Show full text]
  • Q3 2020 Husky-MDA
    MANAGEMENT’S DISCUSSION AND ANALYSIS October 29, 2020 Table of Contents 1.0 Summary of Quarterly Results 2.0 Business Overview 3.0 Business Environment 4.0 Results of Operations 5.0 Risk Management and Financial Risks 6.0 Liquidity and Capital Resources 7.0 Critical Accounting Estimates and Key Judgments 8.0 Recent Accounting Standards and Changes in Accounting Policies 9.0 Outstanding Share Data 10.0 Reader Advisories 1.0 Summary of Quarterly Results Three months ended Quarterly Summary Sep. 30 Jun. 30 Mar. 31 Dec. 31 Sept. 30 Jun. 30 Mar. 31 Dec. 31 ($ millions, except where indicated) 2020 2020 2020 2019 2019 2019 2019 2018(1) Production (mboe/day) 258.4 246.5 298.9 311.3 294.8 268.4 285.2 304.3 Throughput (mbbls/day) 300.1 281.3 307.8 203.4 356.4 340.3 333.6 286.9 Gross revenues and Marketing and other(1) 3,379 2,408 4,113 4,921 5,373 5,321 4,610 5,042 Net earnings (loss) (7,081) (304) (1,705) (2,341) 273 370 328 216 Per share – Basic (7.05) (0.31) (1.71) (2.34) 0.26 0.36 0.32 0.21 Per share – Diluted (7.06) (0.31) (1.71) (2.34) 0.25 0.36 0.31 0.16 Cash flow – operating activities 79 (10) 355 866 800 760 545 1,313 Funds from operations(2) 148 18 25 469 1,021 802 959 583 Per share – Basic 0.15 0.02 0.02 0.47 1.02 0.80 0.95 0.58 Per share – Diluted 0.15 0.02 0.02 0.47 1.02 0.80 0.95 0.58 (1) Gross revenues and Marketing and other results reported for 2019 have been recast to reflect a change in reclassification of intersegment sales eliminations and a change in presentation of the Integrated Corridor and Offshore business units.
    [Show full text]
  • Initial Project Description Summary
    SUNCOR ENERGY INC. Base Mine Extension INITIAL PROJECT DESCRIPTION SUMMARY February 2020 SUNCOR ENERGY INC. Base Mine Extension - Initial Project Description Summary February 2020 This Page Intentionally Left Blank SUNCOR ENERGY INC. Base Mine Extension - Initial Project Description Summary February 2020 EXECUTIVE SUMMARY Suncor Energy Inc. (Suncor) is submitting a proposal to develop the Base Mine Extension Project (the Project). All plausible pathways to address global emissions need energy from fossil fuels and Suncor views Canada’s world class, strategic oil sands resource as a key part of the energy future for decades to come. Commensurate with Canada’s ambitions, Suncor is committed to a long-term strategy of reducing absolute emissions. With the innovation we are known for, Suncor can provide the world with trusted low carbon energy. Suncor has invested billions of dollars in infrastructure that produces value added products to meet the energy needs of Albertans and Canadians. This Project is necessary to continue to add value with this infrastructure. The bitumen from this project will be used to supply the existing upgraders at Suncor’s Oil Sands Base Plant operations (Base Plant), when the existing mines are depleted. The Project is adjacent to Base Plant and includes an open pit mining operation and extraction facilities. Production is expected to be nominally 225 thousand barrels per day of replacement bitumen during its estimated 25-year operational life. The Project application will be based on best-available technology. In parallel, Suncor is developing new technologies, such as non-aqueous extraction. These new technologies have the potential to significantly reduce the overall footprint, reclamation timeline, and GHG emissions of mining and will be incorporated as appropriate.
    [Show full text]
  • Suncor Energy – Investor Presentation 2019 Q1
    INVESTOR INFORMATION Q1 2019 Published May 1, 2019 2 Canada’s leading integrated energy company $85B ~940 mbpd ~600 mbpd 28+ years ~460 mbpd ~1750 1 Oil production Heavy upgrading 2P Reserve life Refining nameplate Enterprise value Retail sites4 As at March 31, 2019 nameplate capacity2 nameplate capacity2 index3 capacity2 1, 2, 3, 4 See Slide Notes and Advisories 3 Suncor – A resilient business focused on shareholder returns Cash flow growth Cash generation Strong potential FFO1 increase largely independent of market conditions Significant upside FFO1 sensitivity to WTI, based on TTM5 actuals US$62.80 WTI, 0.76 C$/US$, US$18.00 NYH 3-2-1 crack spread 2 (C$ billion) ~5% CAGR (Based on 2019 price guidance) $16 $14 TTM average production 750 mbbls/d $12 Debottlenecks, $10 cost reductions $8 Fort Hills, and margin Syncrude, improvements $6 and Hebron $4 $5.5B Sustaining capital6 + dividend $2 $2.8B Sustaining capital6 $0 2018 FFO1 Production Free funds flow 2023E FFO1 $60 $63 $70 $75 $80 growth 3 growth4 TTM WTI ($USD) Shareholder returns Resilience Commitment to reliable returns through the commodity cycles Managing the balance sheet as a strategic asset Dividend per share7 Liquidity Buyback per share7,8,9 Anticipated buyback per share7,9 7% $5.3B $1.9B cash and $3.4B in available lines of credit Dividend + buyback yield As at March 31, 2019 — 5% 5% A low Credit rating 1.88 Investment grade 0.85 DBRS (A Low) Stable, S&P(A-) stable, Moody’s (Baa1) Stable 1.14 3% 3% Baa1 WTI FFO Break-Even10 (USD) 1.02 1.14 1.16 1.28 1.44 1.68 ~$45 Sustaining capital6 + dividend 2014 2015 2016 2017 2018 2019E 2019 1, 2, 3, 4, 5, 6, 7, 8, 9, 10 See Slide Notes and Advisories.
    [Show full text]
  • Secure Fuels from Domestic Resources ______Profiles of Companies Engaged in Domestic Oil Shale and Tar Sands Resource and Technology Development
    5th Edition Secure Fuels from Domestic Resources ______________________________________________________________________________ Profiles of Companies Engaged in Domestic Oil Shale and Tar Sands Resource and Technology Development Prepared by INTEK, Inc. For the U.S. Department of Energy • Office of Petroleum Reserves Naval Petroleum and Oil Shale Reserves Fifth Edition: September 2011 Note to Readers Regarding the Revised Edition (September 2011) This report was originally prepared for the U.S. Department of Energy in June 2007. The report and its contents have since been revised and updated to reflect changes and progress that have occurred in the domestic oil shale and tar sands industries since the first release and to include profiles of additional companies engaged in oil shale and tar sands resource and technology development. Each of the companies profiled in the original report has been extended the opportunity to update its profile to reflect progress, current activities and future plans. Acknowledgements This report was prepared by INTEK, Inc. for the U.S. Department of Energy, Office of Petroleum Reserves, Naval Petroleum and Oil Shale Reserves (DOE/NPOSR) as a part of the AOC Petroleum Support Services, LLC (AOC- PSS) Contract Number DE-FE0000175 (Task 30). Mr. Khosrow Biglarbigi of INTEK, Inc. served as the Project Manager. AOC-PSS and INTEK, Inc. wish to acknowledge the efforts of representatives of the companies that provided information, drafted revised or reviewed company profiles, or addressed technical issues associated with their companies, technologies, and project efforts. Special recognition is also due to those who directly performed the work on this report. Mr. Peter M. Crawford, Director at INTEK, Inc., served as the principal author of the report.
    [Show full text]
  • Suncor Energy Announces Successful Acquisition of 72.9% of Canadian Oil Sands Shares
    News Release FOR IMMEDIATE RELEASE Suncor Energy announces successful acquisition of 72.9% of Canadian Oil Sands shares (All dollar amounts referenced are in Canadian dollars) Calgary, Alberta (Feb. 5, 2016) – Suncor announced today that approximately 72.9 per cent of Canadian Oil Sands shares (“COS”) equating to 353,307,264 common shares and accompanying rights have been tendered to Suncor's Offer. Suncor will take up all tendered shares and those shares will be paid for in accordance with the terms of the Offer, initially made October 5, 2015 and most recently amended January 22, 2016. All shares tendered were held by "Independent Shareholders" as such term is defined by the COS shareholder rights plan dated December 31, 2010 as amended April 30, 2013 (the “COS Rights Plan”). “We’re pleased with the strong level of support from COS shareholders,” said Steve Williams, president and chief executive officer. “From the outset, we’ve spoken about the excellent value this offer creates for both COS and Suncor shareholders and I’m looking forward to delivering on that commitment.” In accordance with the "Permitted Bid" requirements of the COS Rights Plan and the terms of the Offer, Suncor has extended its Offer to Monday, February 22, 2016 at 5:00 p.m. MT (7:00 p.m. ET) so that COS shareholders who have not yet tendered their shares can do so. Further extensions beyond February 22, 2016 are not anticipated. COS shareholders who tendered to the Offer will receive 0.28 of a common share of Suncor for each share, which will be paid in accordance with the terms of the Offer.
    [Show full text]
  • Pride Drillships Awarded Contracts by BP, Petrobras
    D EPARTMENTS DRILLING & COMPLETION N EWS BP makes 15th discovery in ultra-deepwater Angola block Rowan jackup moving SONANGOL AND BP have announced west of Luanda, and reached 5,678 m TVD to Middle East to drill the Portia oil discovery in ultra-deepwater below sea level. This is the fourth discovery offshore Saudi Arabia Block 31, offshore Angola. Portia is the 15th in Block 31 where the exploration well has discovery that BP has drilled in Block 31. been drilled through salt to access the oil- ROWAN COMPANIES ’ Bob The well is approximately 7 km north of the bearing sandstone reservoir beneath. W ell Keller jackup has been awarded a Titania discovery . Portia was drilled in a test results confirmed the capacity of the three-year drilling contract, which water depth of 2,012 m, some 386 km north- reservoir to flow in excess of 5,000 bbl/day . includes an option for a fourth year, for work offshore Saudi Arabia. The Bob Keller recently concluded work Pride drillships in the Gulf of Mexico and is en route to the Middle East. It is expected awarded contracts to commence drilling operations during Q2 2008. Rowan re-entered by BP, Petrobras the Middle East market two years ago after a 25-year absence. This PRIDE INTERNATIONAL HAS contract expands its presence in the announced two multi-year contracts for area to nine jackups. two ultra-deepwater drillships. First, a five-year contract with a BP subsidiary Rowan also has announced a multi- will allow Pride to expand its deepwater well contract with McMoRan Oil & drilling operations and geographic reach Gas Corp that includes re-entering in deepwater drilling basins to the US the Blackbeard Prospect.
    [Show full text]
  • Facts About Alberta's Oil Sands and Its Industry
    Facts about Alberta’s oil sands and its industry CONTENTS Oil Sands Discovery Centre Facts 1 Oil Sands Overview 3 Alberta’s Vast Resource The biggest known oil reserve in the world! 5 Geology Why does Alberta have oil sands? 7 Oil Sands 8 The Basics of Bitumen 10 Oil Sands Pioneers 12 Mighty Mining Machines 15 Cyrus the Bucketwheel Excavator 1303 20 Surface Mining Extraction 22 Upgrading 25 Pipelines 29 Environmental Protection 32 In situ Technology 36 Glossary 40 Oil Sands Projects in the Athabasca Oil Sands 44 Oil Sands Resources 48 OIL SANDS DISCOVERY CENTRE www.oilsandsdiscovery.com OIL SANDS DISCOVERY CENTRE FACTS Official Name Oil Sands Discovery Centre Vision Sharing the Oil Sands Experience Architects Wayne H. Wright Architects Ltd. Owner Government of Alberta Minister The Honourable Lindsay Blackett Minister of Culture and Community Spirit Location 7 hectares, at the corner of MacKenzie Boulevard and Highway 63 in Fort McMurray, Alberta Building Size Approximately 27,000 square feet, or 2,300 square metres Estimated Cost 9 million dollars Construction December 1983 – December 1984 Opening Date September 6, 1985 Updated Exhibit Gallery opened in September 2002 Facilities Dr. Karl A. Clark Exhibit Hall, administrative area, children’s activity/education centre, Robert Fitzsimmons Theatre, mini theatre, gift shop, meeting rooms, reference room, public washrooms, outdoor J. Howard Pew Industrial Equipment Garden, and Cyrus Bucketwheel Exhibit. Staffing Supervisor, Head of Marketing and Programs, Senior Interpreter, two full-time Interpreters, administrative support, receptionists/ cashiers, seasonal interpreters, and volunteers. Associated Projects Bitumount Historic Site Programs Oil Extraction demonstrations, Quest for Energy movie, Paydirt film, Historic Abasand Walking Tour (summer), special events, self-guided tours of the Exhibit Hall.
    [Show full text]
  • Suncor Energy – Annual Report 2005
    Suncor05ARcvr 3/8/06 1:33 PM Page 1 SUNCOR ENERGY INC. 2005 ANNUAL REPORT > growing strategically Suncor’s large resource base, growing production capacity and access to the North American energy market are the foundation of an integrated strategy aimed at driving profitable growth, a solid return on capital investment and strong returns for our shareholders. A staged approach to increasing our crude oil production capacity allows Suncor to better manage capital costs and incorporate new ideas and new technologies into our facilities. production 50,000 bpd 110,000 bpd (capacity) resources Third party bitumen 225,000 bpd Mining 260,000 bpd 350,000 bpd 500,000 bpd In-situ 500,000 – 550,000 bpd OUR PLANS TO GROW TO HALF A MILLION BARRELS PER DAY IN 2010 TO 2012* x Tower Natural gas Vacuum 1967 – Upgrader 1 1998 – Expand Upgrader 1, Vacuum Tower Future downstream integrat 2001 – Upgrader 2 Other customers 2005 – Expand Upgrader 2, 2008 – Further Expansion of Upgrader 2 2010-2012 – Upgrader 3 Denver refinery ion Sarnia refinery markets To provide greater North American markets reliability and flexibility to our feedstock supplies, we produce bitumen through our own mining and in-situ recovery technologies, and supplement that supply through innovative third-party agreements. Suncor takes an active role in connecting supply to consumer demand with a diverse portfolio of products, downstream assets and markets. Box 38, 112 – 4th Avenue S.W., Calgary, Alberta, Canada T2P 2V5 We produce conventional natural Our investments in renewable wind tel: (403) 269-8100 fax: (403) 269-6217 [email protected] www.suncor.com gas as a price hedge against the energy are a key part of Suncor’s cost of energy consumption.
    [Show full text]
  • Husky Energy Ltd
    CLEAN ENERGY FINAL REPORT PACKAGE Project proponents are required to submit a Final Report Package, consisting of a Final Public Report and a Final Financial Report. These reports are to be provided under separate cover at the conclusion of projects for review and approval by Alberta Innovates (AI) Clean Energy Division. Proponents will use the two templates that follow to report key results and outcomes achieved during the project and financial details. The information requested in the templates should be considered the minimum necessary to meet AI reporting requirements; proponents are highly encouraged to include other information that may provide additional value, including more detailed appendices. Proponents must work with the AI Project Advisor during preparation of the Final Report Package to ensure submissions are of the highest possible quality and thus reduce the time and effort necessary to address issues that may emerge through the review and approval process. Final Public Report The Final Public Report shall outline what the project achieved and provide conclusions and recommendations for further research inquiry or technology development, together with an overview of the performance of the project in terms of process, output, outcomes and impact measures. The report must delineate all project knowledge and/or technology developed and must be in sufficient detail to permit readers to use or adapt the results for research and analysis purposes and to understand how conclusions were arrived at. It is incumbent upon the proponent to ensure that the Final Public Report is free of any confidential information or intellectual property requiring protection. The Final Public Report will be released by Alberta Innovates after the confidentiality period has expired as described in the Investment Agreement.
    [Show full text]
  • Environmental Effects Monitoring Design Report
    Environmental Effects Monitoring Design Report Appendix A Approach to Baseline WR-HSE-RP-2008, Ver 1 Appendix A Page 1 of 3 Environmental Effects Monitoring Design Report Incorporation of New Drill Centres into the White Rose EEM Program Selection of Station Locations Sampling and statistical analyses of Environmental Effects Monitoring (EEM) data at White Rose occurs at micro- and macro-scales within the nearfield and farfield regions to address zones of influence (ZOI). The nearfield is that region described by the immediate influence of the drill centres. The farfield region is the area further out along transects outside the nearfield area. As such, the design includes a survey grid centered on the FPSO and a second series of stations centered on the location of drill centres. Husky Energy’s approach to sampling drill centre areas in the nearfield has been to sample six stations located 1 km from the proposed location of new drill centres. This approach accommodates a 1.5-km movement of drill centres should the proposed location change. The approach was employed during initial baseline collection in 2000 (Husky Energy 2001) and for sampling around the potential new drill centre at the NN and South White Rose Extension (SWR-X) drill centres in 2004 (Figure 1). With slight variation, this approach was used again in 2006 for the proposed West Alpha and West Bravo drill centres (Figure 1). Once the location of new drill centres is finalized, three or four of the nearest drill centre stations are retained1 depending on projected drilling intensity, and one new station is added 300 m from the drill centre in the following sampling year if drilling has occurred at that drill centre.
    [Show full text]
  • Foreign Investment in the Oil Sands and British Columbia Shale Gas
    Canadian Energy Research Institute Foreign Investment in the Oil Sands and British Columbia Shale Gas Jon Rozhon March 2012 Relevant • Independent • Objective Foreign Investment in the Oil Sands and British Columbia Shale Gas 1 Foreign Investment in the Oil Sands There has been a steady flow of foreign investment into the oil sands industry over the past decade in terms of merger and acquisition (M&A) activity. Out of a total CDN$61.5 billion in M&A’s, approximately half – or CDN$30.3 billion – involved foreign companies taking an ownership stake. These funds were invested in in situ projects, integrated projects, and land leases. As indicated in Figure 1, US and Chinese companies made the most concerted efforts to increase their profile in the oil sands, investing 2/3 of all foreign capital. The US and China both invested in a total of seven different projects. The French company, Total SA, has also spread its capital around several projects (four in total) while Royal Dutch Shell (UK), Statoil (Norway), and PTT (Thailand) each opted to take large positions in one project each. Table 1 provides a list of all foreign investments in the oil sands since 2004. Figure 1: Total Oil Sands Foreign Investment since 2003, Country of Origin Korea 1% Thailand Norway 6% UK 7% 2% US France 33% 18% China 33% Source: Canoils. Foreign Investment in the Oil Sands and British Columbia Shale Gas 2 Table 1: Oil Sands Foreign Investment Deals Year Country Acquirer Brief Description Total Acquisition Cost (000) 2012 China PetroChina 40% interest in MacKay River 680,000 project from AOSC 2011 China China National Offshore Acquisition of OPTI Canada 1,906,461 Oil Corporation 2010 France Total SA Alliance with Suncor.
    [Show full text]