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Alberta Heavy Oil Royalties

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					Alberta Heavy Oil (Oil Sands)
          Royalties

        November 18th, 2010

 Adam Battistessa
 Senior Advisor, Global Royalty Policy
 Shell Canada Limited
         Oil Sands Royalty Regulations Agenda


•   NPI (Net Profit Interest) or Net Revenue System
•   Royalty Rates
•   Project Definitions
•   Project and Expansion Criteria
•   Application Requirements
•   OSRR (Oil Sands Royalty Regulation) Specific Issues
           •   Emerging/Developing Issues
           •   Heavy Oil Project Ring-fence Example
           •   Longer Term Issues

•   Default Royalty Arrangements:
     –   Conventional Oil
     –   Natural Gas (Solution Gas)
          4 Hard Truths about OS Royalties

•Relationships are Crucial with Stakeholders

•Political-Economic Dynamics




•Business Rules Certainty

•Materiality
                            OSRR Net Profit Interest (NPI)
•   Legislated Royalty Regime:
     – Alberta Government owns the resource (81% of all P&G and OS Leases)
     – 80% of OS Leases are recoverable through In-situ

•   OS royalties is forecasted to be the largest royalties contributor
•   Revenue minus Costs
•   Patient Landlord Concept (relative to Conventional):
     –   Lower rates until costs + return allowance (LTBR) are recovered
     –   Rate increase after payout based on ability to pay (Net Revenues)
•   Why NPI?
     –   Lowers downside risk
     –   Crown shares in limited risks
     –   Helps to open remote/greenfield/brownfield areas
           •   New generation In-situ technologies
           •   Directionally in alignment the AB Energy Strategy (2008)

     –   Fosters risky/high cap development
                       OSRR Net Profit Interest (NPI)


•   Default position without an OSRR Approval:
     – Mines: 20% of Gross Revenues from initial production
     – In-situ: Conventional Oil Royalty Regulations
           • Up to 50% of Gross Revenues prior to 2011 (before incentives)
           • 40% Max effective Jan 1st, 2010 (before incentives)

•   Other regimes similarly structured in Canada: BC, NL, NS, NWT
•   International: Australia - PRRT, New Zealand – MPP, Alaska - PPT, UK - PRT
•   Comparability
     –   Different: cost deductability, Cost uplifts, Royalty Tier triggers (RAs, R-factor, and IRRs),
         Return Allowances, etc...
     –   Full Fiscal take needs to be assessed
     –   Not easily comparable to OSRR (risks, geology, extraction, technology differs)
                                  Generic OSRR 2009 Rates
•   Sliding scale based on WTI
     –   Effective January 2009
     –   $55-120/bbl WTI CDN for the period
     –   No Indexing Treatment on Trigger Pricing

•   Pre-payout:
     –   1-9% of Gross Revenue (Sales Revenue less Transportation Costs)
     –   Settled Monthly

•   Post-payout:                                                                               Alberta Energy - Oil Sands Website

     –   Greater of: 1-9% of Gross Revenue or 25-40% of Net Revenue (Gross Revenue less Capital and Opex)
     –   Marginal projects more likely of paying on gross revenue (Net Loss for the period)
     –   Instalments based on a Good Faith Estimate and settled at the end of the yearly period

•   Previous to 2009 Rates (1997 OSRR)
     –   Pre-payout: 1% of Gross Revenues
     –   Post-Payout: Greater of 1% of Gross Revenues or 25% of Net Revenues

•   Crown Agreements
     –   Initial ring-fencing arrangements with Crown (e.g. Suncor and Syncrude)
     –   All CA agreements are being transitioned to Generic Regime

•   Experimental Oil Sands Royalty Regulations (1984/1992)
     –   1% /5% of Gross Revenues
                                                   Ring Fence
                               (S. 11, 12, and 14 – Approvals/Project Description)

•   Royalty Legal Entity (Ministerial Orders - MOs)
•   Collection of ERCB scheme approvals, facilities, equipment, lands, leases, processes,
    and constraints
•   Determines royalty calculation point, affiliated relationships, and allowed costs
•   Land based vs. well based approvals
•   Asset Classes and related thresholds
     –   Core vs. Supporting Assets
     –   Maximum Capacity Constraints
     –   Maximum Time Constraints

•   Off-project Lands facilities
     –   Disposal Well
     –   Cost-of-Service for Basic and Non-Basic Services

•   Emerging Conditions on Approvals
     –   Heat Transfer
     –   Solution Gas Assets
     –   Partially Includable Assets in Projects
Alberta’s Oil Sands Projects
                        OSRR Minimum Project Criteria
                                (S. 11 and 14 – Approvals/Project Description)

•   Must apply to ADOE (Alberta Department of Energy) for OSR approval
     –   ERCB scheme approval must be present
     –   Lengthy application process (at least 9 months)
     –   Follow-up consultations
•   Reservoir in an ERCB defined geographic area
•   Facilities and processes – 50Km rule
     –   Capacities and thresholds
•   Holder of an Oil Sands Lease(s)
•   JV interests consistent across the project
•   Economically viable
     –   Payout achievability
     –   NPV positive
     –   Pilot and Experimental Projects (In consultations)
•   Expected Oil Sands Products extracted
•   Historical Costs (PNCB)
                  Project Amendments (Expansions)
                                (S. 10 S. 11 – Applications/Approvals)



•   Expansions are not automatically given and must applied for
•   Potential Expansions Triggers:
     – Adding new wells (well based approvals)
     – Change in extraction type or well type (vertical vs. horizontal)
     – Exceeding Maximum Production Capacity
     – Debottlenecking/facility expansion
     – Adding new facilities or lands
     – ERCB Scheme amendments:
          • Changing project scope
          • Adding new project lands
            Project Amendments (Expansions) Criteria
                                      (S. 10 S. 11 – Applications/Approvals)

•   Rules and assessments are contingent on Ministerial
    discretion/interpretation and current on-going consultations with the ADOE
•   Common Management and operationally integrated
•   Technical consistency between phases (extraction and processing)
•   MPC (maximum Production Capacity), MPT (Maximum Production Time)
•   Royalty Payable – Impact to the Crown
     –   Payout deferral
     –   Stand Alone vs. Integrated Projects
     –   Current Economic Viability
     –   Cost of Service (COS)
         for shared facilities and non-project facilities on basic/non-basic services

•   JV interests consistent across all phases
•   Project geographically/geologically contiguous
                                      Application Information
                                                  (S. 10 – Applications)

•   Documentation
     –   Project History and Description
     –   Lands/Leases/Mineral Rights
     –   Project Operations
     –   Project Facility/well locations/process flow diagrams/plots
     –   Geological Assessments
           •   Reservoir Properties

     –   ERCB applications/approvals
     –   UWI, licences, type, drill dates
     –   Historical Costs/Revenues/Production (PNCB)
           •   Conventional Royalty paid

     –   Forecasted Costs/Revenues/Production
     –   JV and JOA documentation
     –   Economic Assessments and Royalty impacts to the government
     –   AFEs……..

•   Cross-functional coordination
•   Follow-up work:
     –   Consultations
     –   Presentation
     –   Site visits
                    OSRR Developing/Emerging Issues

•   Bitumen Valuation Methodology (BVM)
     –   Gross Product Worth (GPW)

•   Cost Allocation of Engineering Systems
     –   Engineering Systems (e.g. Cogeneration and Steam Production)
     –   Heat Transfer

•   Solution Gas/Oil Sands Product
•   CARE (Cost Analysis and Reporting Enhancements)            Forms Requirements


•   Allowable Costs Tightening
     –   90 day cost incurred
     –   Accruals

•   Historical Costs Limitations
     –   Stratigraphic Wells

•   Project Definitions
     –   Cross Boundary Wells and Excluded (PSR) Wells (Example)

•   Change of Use Rules
•   Reserves - SEC (Net of Royalties implications)
•   Competitiveness Review (OSRR is not in scope)
Bitumen Valuation Methodology (BVM)

 •   New Ministerial regulation (2009)
      –   Applied to all generic OSR ring-fences
      –   Crown Agreements prior to 2009

 •   Arms length vs. Non-Arms length (NAL – affiliate rules – S. 2)
      –   Determined at Royalty Calculation Point

 •   NAL transactions valued at BVM
      –   Third Party Disposition Threshold - 40% rule – S 8(d)
      –   Remaining AL transactions still valued at Market prices

 •   Staged method
      –   2009: Western Canada Select Blend (WCS) @ Hardisty adjusted for density
          of each NAL project
      –   2012 onward: WCS based with potential refinements (GPW)

 •   Sales Revenue for Royalty purposes on a clean dry bitumen basis at
     royalty ring-fence (unblended bitumen)
 •   Floor Price (Maya based)
                                     Bitumen Valuation Methodology (BVM)
BVM Calculation: (all calculations on a monthly basis)
                                                                                                   F/X, $C/$US
                                    Bitumen synbit              (1‐ Dilbit )fraction
                                    premium, $US/bbl       x

                                                                                                   Bbl to M3,
                                                                                                   /6.29234

                                                 BVM Dilbit
                                                 Value Adjustment,
   WTI Price
                                                 $US/bbl
   $US/bbl


                              WCS Settlement 
                                                       ‐             BVM Dilbit Value,                     BVM Dilbit Value,
         +                    Price, $US/bbl                         $US/bbl                               $C/M3


   NTP WCS Index
   $US/bbl

                                 WCS density,                             Dilbit Density                    BVM Dilbit
                                 Kg/m3                                    Adjustment,                       Density,
                                                                          Kg/m3                             Kg/M3




       From these 2 values, a project will                                              Bitumen Syn/Dil            BVM Calculation: (all calculations on a monthly basis)
       calculate its individual BVM, based                                              Blending 
                                                   (1‐ Dilbit )fraction
       on its royalty bitumen density and                                        x      Differential
       transportation costs.
                                                                                                                                                                         Blending Model
                                                                                                                                       Project Bitumen
                                                                                                                                       Density,                                                          BVM Diluent
                                                                                                                                       Kg/M3                                                             Volume


                                                                                                                                                                              API 12.3
                                                                                                                                       Condensate (CRW)
                                                                                                                                       Density,                                                          BVM Blend
                                                                                                                                       Kg/M3                                                             Volume


                                                                                                                   BVM Diluent Volume = The volume in m3 of condensate(CRW) needed to blend 1m3 of project bitumen to BVM dilbit density.

                                                                                                                   BVM Blend Volume = The volume of project dilbit resulting from the blending of 1m3 of project bitumen with the BVM Diluent
                                                                                                                   Volume.

                                                                                                                   BVM Calculation: Value of Project Bitumen at Hardisty


                                                                                                                     Bitumen Value @                                                                                         Condensate
                                                                                                                     Hardisty,
                                                                                                                     $C/m3
                                                                                                                                        =         BVM Blend
                                                                                                                                                  Volume, m3
                                                                                                                                                                x      BVM Dilbit
                                                                                                                                                                       Value,                -       BVM Diluent
                                                                                                                                                                                                     Volume, m3
                                                                                                                                                                                                                       x     Allowance
                                                                                                                                                                                                                             Price, $C/m3
                                                                                                                                                                       $C/m3
Cost Allocations of Engineering Systems
•   Allocation of Project Facilities and Common
    Costs
     –   Royalty Project facilities
     –   Shared Facilities
     –   Non-project Facilities

•   Methods to determine Project Use
     –   Direct Measurement
           •   Metered Flows
           •   Time Sheet and Receipt Systems

     –   Design Intent (Engineering calculations)
           •   Utility Balance Diagrams
           •   PFDs and P&ID

     –   Indirect Calculation
           •   Head Count Ratio
           •   Capital Cost Ratio
           •   Geographic Boundary Ratio

•   Cost of Service (COS)
•   Partially Included Assets
     –   5 systems are not permitted to be partially
         included

•   Project by project assessment with generic
    rules applicable
•   Impacts are mostly with integrated
    operations (with Upgrader on-site)
Engineering Systems Cost Allocations proposed by the ADOE
 General Papers:
 1. Method of Calculation for Indirect Allocation Ratios on Integrated Oil Sands Projects
 2. Allocations of Engineering Systems on Integrated Oil Sands Projects

 System Proposal Papers:
 1. Allocation of Fire Water System Costs
 2. Allocation of Pipe rack Costs
 3. Allocation of Raw Water System Costs
 4. Allocation of Boiler Feed Water Treatment Plant Costs
 5. Allocation of Cooling Water System Costs
 6. Allocation of Fuel Gas System Costs
 7. Allocation of Steam Generation Costs
 8. Allocation of Flare System Costs
 9. Allocation of Control System Costs
 10. Allocation of Transmission Infrastructure Costs
 11. Allocation of Emergency Power System Costs
 12. Cogeneration Systems and their Cost Allocation
 13. Valuation of Internally Produced Fuels in Integrated Oil Sands Projects
 14. Allocation and Valuation of Heat Transfer System Costs

 Supplemental Papers:
 1. General Cost Allocation - For Consultation With Industry
 2. Cost of Service Summary Paper for CAPP
 3. Heat Transfer Calculation - Example
    Heat Transfer
•   Heat flows to and from ring-fences has value at the RCP
     –   Crown participates in costs to create Heat
     –   WIP (5 years) with ADOE but close to complete

•   Thermal Energy flows crossing ring-fences
     –   Diluted Bitumen (Dilbit) and Diluent streams
     –   Product streams
     –   Pump Around (PA) streams to the Diluent Recovery Unit (DRU)
     –   Process Heat (PH) streams
     –   Condensate (C) streams
     –   Low Grade Energy (LGE) streams

•   Thermal Dynamic principles of Exergy and Enthalpy
    considered in previous proposals
     –   Exergy (undervalues high temp heat values)
     –   Enthalpy (overvalues low temp heat values)
    Heat Transfer – Calculation Determination
•    Identify the net enthalpy transfer rate for each stream, assuming full enthalpy transfer between
     starting, and final temperatures for the stream which is transferring enthalpy.
•    Apply the Synergy Factor for each enthalpy rate, to obtain the synergy adjusted enthalpy rate.
•    Sum the synergy adjusted enthalpy amounts entering the royalty Project (+), and leaving the
     royalty Project (-) to get a net enthalpy transfer rate.
•    Compare the net enthalpy rate to the net bitumen production rate, to obtain a net enthalpy rate
     per barrel of bitumen for each Project. This is unlikely to change until a significant change
     occurs to the Project.
•    Determine the SWTEV (Site Wide Thermal Energy Value) for each project, each year.
•    Multiply the enthalpy per barrel x the SWTEV x actual bitumen production for the year to
     determine the allowed cost (+), or ONP (-) for the year.
Solution Gas/Oil Sands Product


•   Definition
     –   Dissolved in crude bitumen under initial reservoir
         conditions and includes any that evolves from pressure
         change due to human disturbance, but does not include
         gas produced through chemical alteration of crude
         bitumen using high temperature, high pressure, a
         catalyst, or otherwise
•   WIP with DOE
     –   ADOE preference: falls under Ng royalty regulations
•   “Cracked Gas” is an Oil Sands Product and is
    included under Gross Revenues
•   Otherwise flared solution gas waivers
•   Natural Gas Regs incentives:
     –   5% NWRR
Ring-Fence Example: Non-project (PSR) Wells and Cross-
               Boundary Wells Issues
                                                    • Pad 2 does not have
                                                    OSR approval but has
                                                    ERCB scheme amendment
                                                    approval (#2)
                 Pad 3
                                                    • Both Surface and
                                                    subsurface must be inside
                                                    the ring-fence

                                                    • Pay Conventional Oil
                                                    Royalties until OSR
       Pad 1                                        amendment approval is
                                                    obtained
                  Pad 2
                                                    • OSR approval for Pad 2 is
                                                    not necessarily guaranteed
                                                    (Conventional Regime)

                                                    • If separate expansion ring-
                                                    fence OSR approval
                                   OSR123
                                                    (OSR123A) is attained to
                                                    include non-project wells,
                                                    then all allocation of costs
                                   ERCB Scheme #1
                                                    and production based on
                                                    production zone of legs
                                   OSR123A



                                   ERCB Scheme #2
                     OSRR Longer-term Issues


•   Bitumen Royalty Take-in-kind (BRIK)
•   Pilot/Experimental Project
•   GHG & CO2 Compliance Cost
•   Indexing
•   Abandonment and Reclamation
     –   ERCB Incompatibility Directives: MFSP, LFLMP, Orphan Well Fund
     –   Post production costs deductibility
     –   Ring-fencing
                      Summary
• Materiality of Royalty implications are significant
(economic viability considerations)

• Oil Sands royalty regulations/rules are not as
certain as perceived

• Rules and interpretations do change over time
depending on political and economic dynamics

• Strong communications internal and external
stakeholders necessary to reach optimal royalty
arrangements

• Issues and challenges are common with other
jurisdictions around the globe
Questions?

				
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