TNUoS Charges Onshore Methodology Potential application offshore

1
TNUoS Charges- Onshore Methodology- Potential
application offshore

• January 2007

2
Objectives

• A guide to the governance, principles and
  mechanics behind Transmission Use of System
  charging
• National Grids Transmission Licence obligations
• Overview of TNUoS tariffs onshore
• Principles
• Locational element
• Residual element
• Design Variation Discount proposal
• Calculation of illustrative example of tariffs

3
Transmission Licence conditions

• The Transmission Licence places legal obligations
  upon the licence holders
• C5 - TNUoS charges must meet the relevant
  licence objectives
• Facilitating competition
• Reflect costs incurred
• Take account of developments in the transmission
  business
• Methodology modification process
• C7 - Prohibits discrimination between classes of
  User
• CUSC 3.9 - Requires Users to pay TNUoS charges in
  accordance with the Statement of Use of System
  Charges

4
Principles of TNUoS Charges

• Method of recovering cost of building, operating
  and maintaining the electricity transmission
  network
• Allowed revenue determined by Transmission Owner
  price controls every five years
• Efficient, economic signals are provided to Users
  when services are priced to reflect the
  incremental cost of supplying them
• Charges reflect the impact users at different
  locations have on TO costs from a unit increase/
  decrease in their network use
• System is designed to comply with the System
  Security and Quality of Supply Standard
• Based upon peak demand

5
Charging Objectives

• In addition to Licence Condition C5, further
  objectives of the charging methodology include
  the provision of
• Transparency
• Simplicity
• Predictability
• Stability
• Reproducibility

6
Transport Model
7
DCLF

• TNUoS tariff has two elements
• Locationally varying element
• derived from ICRP DCLF
• Non locationally varying element
• residual revenue recovery
• ICRP DCLF Investment Cost Related Pricing DC
  Load Flow model

8
DCLF ICRP Transport Model

• Calculates marginal costs of investment in the
  transmission system which would be required as a
  consequence of an increase in demand or
  generation at each node
• Measures investment costs in terms of MWkm,
  i.e. if 1 MW was injected on the system at a node
  what would be the net change in units of
  transmission system kilometres

9
Transport Model Inputs

• Demand is modelled at winter peak values
  (consistent with SQSS and therefore investment)
• Contracted generation is scaled to match demand
• Transmission circuit data
• Type (OHL/ Cable)
• Voltage
• Length
• Impedance and reactance
• Expansion factors

10
Expansion Factors

• A voltage and cable/OHL specific coefficient
  representing relative costs of all conductor
  mediums as compared to 400kV OHL
• Offshore Expansion Factors yet to be defined
• Typically based on averaged on historic data and
  a broad range of projects dont exist for
  offshore
• E.g. England Wales
• 400kV OHL - 1.00
• 275kV OHL - 1.74
• 132kv Cable - 27.85

11
DCLF Transport Model Output

• Marginal cost for each node is found by running a
  DC Load Flow model and the total MWkm of GB
  transmission system (winter peak) is found
• 1MW is added at each node, and removed from the
  slack node
• The differential in total MWkm is found
• Can be both positive and negative

12
Tariff Model
13
Demand Generation Zones

• Demand zones represent the boundaries of the DNO
  networks
• Generation zoned following the criteria
• Maximum tariff spread of /- 1/kW
• Geographically and electrically proximate
• Minimum number of zones possible
• Reviewed at price control other than in
  exceptional circumstances
• Where possible, minimal zonal boundary changes
  should be made
• For each demand and generation zone, the
  flow-weighted average for marginal kms is found

14
Tariff calculation

• Zonal marginal km converted to an initial tariff
  by multiplying by Expansion Constant and
  Locational Security Factor
• The Expansion Constant is the annuitised value of
  the infrastructure required to transport 1MW over
  1km
• Derived from the projected cost of 400kV OHL at
  the beginning of each price control
• Using manufacturers budgetary prices, contracts
  let, lead tenders
• Uses a range of OHL types, weighted by recent
  usage
• Maintenance
• Inflated annually by RPI (10.07 2006/07)

15
Global Locational Security Factor

• A network compliant with SQSS security standards
  is secure against all feasible double and single
  circuit faults
• A copy of the DCLF transport model is used that,
  in addition, simulates all such faults
• The worse case fault is found for each node to
  determine the maximum increase in marginal cost
• The Locational Security Factor is the best fit
  ratio of total secured marginal kms and unsecured
  marginal kms
• Reviewed at each price control
• Currently 1.8 (2001 2006)

16
Calculation of Locational Security Factor
17
Tariff Calculations Re-referencing

• To ensure that the correct ratio of recovery is
  made from generation and demand, all zones are
  adjusted or re-referenced
• The Authority has determined this as 7327
  (demand generation)
• A single additive constant is calculated which is
  then added to all zonal marginal km
• Differentials between zones are maintained

18
Tariff Calculations Residual tariff

• To ensure that the correct total permitted TNUoS
  revenue is recovered a residual tariff is added
  to all demand and generation zones (7327 ratio)
• Demand 12.463/kW
• Generation 3.531/kW
• Whilst this adjusts the total revenue recovered
  from demand and generation, the cost-reflective
  differentials between zones are maintained

19
TNUoS Methodology Modification Proposal
SQSS design variations amendment
20
GB SQSS and Current TNUoS Methodology

• GB SQSS includes criteria for variations to
  connection designs higher or lower than the
  specified standard
• Providing this does not
• reduce the security of the MITS below the minimum
  planning criteria specified in the standard
• impact on other customers in terms of investment,
  operational costs or security and quality of
  supply
• compromise Transmission Licence obligations
• Customers must accept uncompensated access
  restrictions in order to avoid additional
  operational costs to other customers
• Current TNUoS charging methodology does not
  provide a mechanism by which investment savings
  are passed through

21
Modification Proposal

• Consists of both
• Substation discount
• Locational discount
• Conclusions report submitted 18th November
• Impact assessment initiated by Authority
• Responses by 26th Jan
• Decision by Feb 16th
• For implementation with 2007/08 tariffs

22
Substation Discount

• To reflect the savings associated with the
  reduced substation asset requirements for on
  shore single circuit connection design
• Propose the following discounts to the residual
  tariff

23
Circuit Discount

• Provides an economic signal equal to the cost
  saving of an entire second circuit
• Circuit discount (/kW)
• Circuit marginal length (km) Exp constant
  (/MWkm) 1000

24
Tariff Illustrative Examples
25
Indicative tariff examples

• Indicative charges for 3 offshore locations with
  2 connection options each
• The Wash
• Lincolnshire
• Thames Estuary
• All connected by a 60km, 132kV AC submarine cable
• Assumptions
• Proposed offshore SQSS accepted
• Charging methodology onshore is applied offshore
• No onshore connection circuits
• SQSS Design Variation Amendment non-veto and
  applied to offshore generation connections
• 2007/08 tariff levels

26
Determining Expansion Factors

• Physical characteristics of typical (BEMA
  figures)
• 132kV, 800mm2, 203MW, 60km
• 500k/km (310k supply 190k lay and bury)
• Unit cost 500k/203 2460/MWkm
• Using an 8.43 annuity factor 207.6/MWkm /yr
• 400kV OHL Expansion Constant 10.07
• Expansion Factor 207.6/10.07 20.6

27
Determining Design Variation Discount

• Substation Discount
• 132kV 1.05/kW
• Circuit Discount
• Circuit marginal length expansion constant /
  1000
• (20.6 60) 10.07 / 1000
• 12.45/kW
• Total Discount
• 12.45 1.05 13.50/kW

28
Example