A DNO Perspective
by
Stephen Parker
for
Structure of Charges Workshop 15 July 2003
Agenda
• Reaction to Ofgem’s Initial Conclusions
– Regulatory Framework
– Charging Proposals
– Detailed Issues
• What Happens Next
– Generator DUoS
– Concepts for a Charging Methodology
– Implementation
• Final Thoughts
Regulatory Framework
Common set of High Level Charging Principles
A good idea but insufficient focus on DNO ability to maintain and
develop an efficient network
Introduce Transmission Style Licence Obligations
Disagree – significant reduction in commercial freedom and
extension of administration
Equalise Treatment of Demand and Generation
Agree but significant issues to be addressed
Charging Proposals
Shallow Connection Charging with Locational DUoS for
EHV & Shallowish Connection Charging with NonLocational DUoS for below EHV
In principle we could support this approach so long as definitional
difficulties can be resolved including;
• Defining Generator DUoS
• Defining Shallowish
• Apportioning DUoS between demand and generation users
• Apportioning DUoS between users at different voltages /
locations
Detailed Issues
Existing Generation Connections
Favour exemption with cut off point by which all customers are
charged on same basis. 15 years?
Tariff Support and O&M
Important element of cost reflective charging. We want to adopt
assets built to our standards and see TSA as a helpful feature of
our commercial positioning
Reinforcement Rule
Not convinced that it is possible to establish a rigid rule
Detailed Issues
Fixed & Variable Charges
Important to retain freedom to adjust the balance of charges to
reflect individual network circumstances
Reactive Power Charges
Welcome this statement – incentives need to be considered
Treatment of EHV Charges
No problems with the current arrangements
Defining Generator DUoS?
• Recovery of additional reinforcement/incentive costs
If recovered locally from individual connectees then equals
deferred connection. If not recovered locally then may imply 2
RABs. Need methodology for apportioning between generators
at different locations/voltages.
• Fixed percentage of overall DUoS revenues
How would this percentage be derived? Still need a
methodology for apportioning between generators at different
locations/voltages.
• Simple entry / exit
Netting off type approach. Maintains supplier hub and
minimises implementation costs. Cost reflective?
Defining Generator DUoS?
Develop Marginal Cost Model
How do you capture the impact of multi-directional flows caused by
the presence of distributed generation?
Working with UMIST to consider how such a model could
be developed
Don’t have all the answers nor a full understanding whether the
approach is practical to implement.
Concepts for a Charging Methodology
Starting from the real network generic entry / exit pricing
models are developed (currently 2 models are developed for
the urban and rural networks)
Each item of plant (transformer, cables, overhead lines) on
the generic network can be classified as being either
generator or demand dominated or (roughly) balanced
If an additional unit is imposed on the plant during the point
of maximum loading then this will require reinforcement.
132 kV
Illustrative Example
33 kV
Description of the System
50 MVA
15 MW
CHP
33 kV
Geff=5MW
11 kV
10 MVA
Wind
Farm
1 MW
3 MVA
Geff=200kW
Two generators:
1 MW wind farm at 11kV
(200kW effective contribution)
15 MW CHP plant at 33kV
(5MW effective contribution)
Three load customers with peaks:
3MW on the 11kV feeder
10MW at the 11kV bus
50MW at the 33kV bus
(Minimum demand 25% of MD)
132 kV
33 kV
50 MVA
What is the maximum flow
through the 11kV feeder?
15 MW
CHP
33 kV
Two conditions need to be
investigated:
11 kV
• Maximum load minus
Effective generation
Geff=5MW
10 MVA
Wind
Farm
• Maximum generation minus
Minimum load
1 MW
3 MVA
Geff=200kW
Maximum flow through 11 kV feeder:
F max
 LAMD  G eff

 max 
 G max  Lmin

LAMD  G eff  3  0.2  2.8MW
G max  Lmin  1  0.25  3  0.25MW
F max  2.8MW
Critical condition for the 11 kV feeder is driven by load
132 kV
57.8MW
33 kV
50 MVA
15 MW
CHP
12.75MW
33 kV
Geff=5MW
12.8MW
11 kV
10 MVA
2.8MW
Wind
Farm
1 MW
3 MVA
Geff=200kW
Repeating the analysis
allows the polarity of the
critical flows for each
component of the network
to be identified.
Concepts for a Charging Methodology
Having established the direction of the critical flows the
polarity of DUoS charges for demand and generation can
be determined (e.g. demand customer will pay for use of all
upstream assets that are demand dominated and get rewarded for
use of all assets that are generation dominated)
Temporal dimension to charging can be introduced by
considering the point of the critical flows (e.g Typically for
demand dominated plant, charges to downstream demand customer
will be based on their peak demand (e.g.winter daytime) while
generator payments will be based on their minimum output (or
effective contribution) and applied during the same on peak period.
Concepts for a Charging Methodology
To set DUoS charges for each individual user, per unit
annuitised capacity costs are allocated to each item of
plant
There is full flexibility in implementation, from generic
location and/or time of use specific or non-specific
(simple, cost reflectivity being compromised) to fully
locational specific time of use charges being applied on
the real system (fully cost reflective and accurate, but
potentially very complex)
Implementation Issues
Practicality
Is the right data available? How many tariffs? Volatility of
charges?
Balancing cost reflectivity against simplicity
May represent a means of establishing EHV charges
Meeting social and environmental objectives
Demand charges and generation charges below EHV to be nonlocational
Final Thoughts?
• Changes to charging arrangements must reflect the
significant change to (some?) distribution networks
that DG will bring about
• Maintaining simplicity will be challenging (is it really
necessary?)
• 1 April 2005 is challenging
• Designing by Committee will be (even more)
challenging