Report No. IRL99440.01
NETWORK
RELIABILITY AND FIRM
POWER CAPACITY
WORKSHOP
HELD AT INDUSTRIAL RESEARCH LIMITED,
GRACEFIELD, FRIDAY 16TH DECEMBER 2005
ISSUES, NEEDS, CONCLUSIONS AND ACTION
POINTS
Prepared by: Dr. Iain Sanders,
Sustainable Innovative Solutions Ltd.
(for Industrial Research Limited)

Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
Table of Contents
1. Introduction Page 3
1.1 Summary Page 3
1.2 Background Page 3
1.3 What is Firm Power Capacity? Page 4
1.4 Why is Network Reliability an Page 4
Issue for New Zealand?
1.5 Overview of the Rest of this Report Page 4
2. Key Conclusions Page 5
3. Action Points Raised Page 12
4. Workshop Summary Page 15
5. Supplementary Feedback from Participants Page 41
6. Appendices Page 42
6.1 Workshop Agenda Page 42
6.2 List of Attendees Page 43
6.3 Alternative Policy Frameworks for DG Page 45
6.4 Capacity Metering for General Customers Page 59
Editorial Statement: We have attempted to faithfully report and draw
conclusions from the presentations and discussions at the workshop. Neither
Industrial Research Limited nor Sustainable Innovative Solutions Limited
necessarily endorse these findings.
Alister Gardiner, Industrial Research Limited.
Iain Sanders, Sustainable Innovative Solutions Limited.
Disclaimer: The Commerce Commission does not comment on policy
matters. The Commission has participated only to explain its approach to
assessing breaches of quality thresholds by electricity lines businesses where
caused by extreme events, and has not participated in discussions on nor
makes any comment in regard to other technical matters or industry design
matters.
Paolo Ryan, Manager, Network Performance Group.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
1. Introduction
1.1 Summary
On Friday December 16th, Industrial Research Limited held a workshop in
Gracefield, Lower Hutt, Wellington, on “Network Reliability Requirements” to
which electricity industry stakeholders contributed.
The purpose of this workshop was to provide an industry forum to discuss key
reliability issues facing network operators in relation to the growing interest in
connection of distributed generation plant.
The workshop presenters in order of appearance were:
• Alan Jenkins, Chief Executive, Electricity Networks Association
• Rodney Doyle, Chief Advisor, Network Performance Group, Commerce
Commission
• Gareth Wilson, Manager of the Electricity Group, Ministry of Economic
Development (MED)
• Robert Reilly, Senior Advisor Retail, Electricity Commission
• Duncan Head, Divisional Manager Business Development, Vector Networks
• Brent Noriss, Engineering Manager, The Lines Company
• Matt Todd, CEO, Eastland Networks Limited
• Robert Reilly (speaking on behalf of Roy Hemmingway, Chair, Electricity
Commission
• Todd Mead, Generation Development Manager, MainPower
• Iain Sanders, CEO, Sustainable Innovative Solutions Limited (formerly of
Industrial Research Limited)
• Alister Gardiner, Hydrogen and Distributed Energy Platform Manager,
Industrial Research Limited
These presenters discussed regulations, policies, technical issues, business
development and research opportunities and challenges associated with
delivering firm power capacity in Distribution networks from conventional
network infrastructure assets (e.g. lines and poles and underground cables)
and alternatives options, including: load management, embedded distributed
generation and storage systems.
1.2 Background
Network reliability is essential to the safe and secure operation of New
Zealand’s electricity delivery infrastructure. Distributed generation adds a new
level of complexity for operating networks. This workshop explored some of
the needs for reliable firm power capacity in New Zealand’s electricity network
infrastructure. Reliability issues were examined from conventional network
delivery and alternative energy generation perspectives.
This workshop was the first in a series of two workshops. The second
workshop (to be held around the middle of 2006) will report on and
demonstrate models and techniques developed by Industrial Research for
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
evaluating the impact of distributed energy resources on network reliability, to
providing a means for objective comparison of different distributed energy
resources against network capacity costs.
1.3 What is Firm Power Capacity?
Firm power capacity is defined as “the provision of power capacity when and
where it is required, with a high degree of certainty” (Industrial Research
Limited). This constitutes firm power capacity as described in this report and
as discussed during the workshop.
1.4 Why is Network Reliability an Issue for New Zealand?
Network reliability is affected by the age and cost of maintaining infrastructure
assets. Alternative energy supply options such as distributed energy
resources may in some circumstances provide more reliable and affordable
energy delivery solutions.
Ageing infrastructure assets can cost too much to maintain – there just isn’t
enough revenue generated from the service provided.
In other places, network delivery capacities are exceeded because growth in
peak demand cannot be met by existing infrastructure capacity.
Complimentary localized dispersed generation can address some of the
network reliability issues mentioned. This is only possible if affordable
distributed generation resources can match the network reliability
requirements of the energy demand needs they address.
1.5 Overview of the Rest of this Report
In the next section (2. Key Conclusions), a summary of the main conclusions
derived from the workshop are presented under appropriate headings that
best define the key points raised.
Following the “Key Conclusions”, is a section that presents a series of action
points (3. Action Points Raised) or recommendations towards helping to
address some of the issues identified as needing urgent attention.
After section three, there is a summary of the entire workshop (4. Workshop
Summary), outlining the main points raised, issues addressed and specific
needs identified by each speaker and the audience in the Q&A sessions
following each formal presentation.
The final section (5. Appendices), provides the workshop agenda (5.1), and a
list of attendees (5.2). A couple of appendices (5.3 and 5.4) describe in further
detail some of the conclusions from a technical, commercial and regulatory
perspective.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
2. Key Conclusions
The following conclusions were derived from the forum discussion and the
question and answer sessions held after each presentation.
These high level conclusions indicate concern about governance in the
industry affecting future reliability through an uncertain investment climate, of
which the future for distributed generation is only one component.
“Sustainable development” was frequently used in the workshop as the
primary need for the industry and government to address. No attempt is made
to define the meaning intended by participants, although network “reliability” is
clearly an important contributor to this concept.
Ref. Key Conclusions
C1 Long-term needs not addressed by short-term political agendas.
a. The energy industry of New Zealand is the economic engine critical
to the nation’s survival and prosperity over the next 25 years.
b. Therefore we need to do a lot more evaluation about what the way
forward for the electricity supply sector ought to be.
c. There are major concerns about the overall lack of integration and
mismatch of issues in the energy sector regarding possible energy
futures and mapping out a suitable path forward.
d. The central generation electricity market model needs to be
supported with reinforcement. We have a bureaucratic structure for
energy policy in New Zealand that is: “confused and has a great deal
of difficulty making decisions” (forum participant).
e. Many reports are being written, submissions made, requests for
information given etc., but no decisions are being made that address
the issues and concerns raised.
f. New Zealand needs an energy strategy to address mid- to long-term
needs.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
Ref. Key Conclusions
C2 Untapped potential for sustainable development due to
fragmented markets.
a. Sustainable development is possible if there is the political will to
succeed, backed by a commitment to make the hard decisions and
consistently pursue policies and directives critical to achieving this
outcome.
b. Sustainable development includes the significant adoption of
distributed energy resources, energy efficient design and utilization,
load management, and energy conservation in buildings, industrial
processes etc.
c. With respect to sustainable development, the question is: what is
technically possible if we have the will to achieve it? What is technically
possible within the timeframes required? Considering grid-
interconnection guidelines, the Resource Management Act (RMA),
Power Purchase Agreements (PPAs) etc.?
d. Credibility is a key issue for policymakers to address if progress is
going to be made. If it is desirable and doable, then why aren’t we
making it happen? I.e. putting structures and policies and standards
and regulations etc. in place that will facilitate the uptake and
establishment of a more sustainable energy market in New Zealand for
our long-term growth and prosperity?
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
Ref. Key Conclusions
C3 Many opportunities missed or lost due to lack of coordinated
planning between Government and industry stakeholders.
a. If barriers to investment in distributed energy resources were
effectively reduced and removed, the New Zealand electricity industry
could experience a transformation, through competition driving
innovation, technology advances, business process and practice
improvements, new product developments and practical contractual,
regulatory and policy design.
b. The electricity market only accounts for about 9% of New Zealand’s
CO2 emissions. Farming is responsible for half the country’s
emissions, and transport takes care of most of the rest. Industrial
transformation would be possible if the electricity industry could help
substantially to reduce farming and transport greenhouse gas
emissions, by focusing on security of supply without increasing CO2
emissions from the energy resources required to achieve it. How much
more can the electricity grid be used to supply the energy demands
that are currently being met by non-electrical thermal conversion
processes? E.g. fuel substitution and methane gas conversion.
c. Poorly thought out strategies for banning wood burning for
environmental reasons is placing an increasing strain on already
capacity-constrained peak loading of networks (and doesn’t account
for peak generation fossil fuel CO2 emissions). Here we have
disincentives for better load management and conservation of energy
resources. How do we create incentives for more efficient and effective
energy management and delivery solutions?
d. There is a major lack of coordination between new generation
planning and network infrastructure utilization for delivering it.
Consequently, many new generation and network infrastructure
investments are suboptimal. Long-term needs are not addressed
through lack of coordinated optimal design of solutions because they
involve competing electricity market stakeholders. Short-term vested
financial interests take priority over long-term sustainable security of
supply.
e. There are great opportunities for New Zealand to implement
sustainable renewable energy options, but it only takes one barrier e.g.
the Resource Management Act to bring an entire project to a halt
indefinitely.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
Ref. Key Conclusions
C4 Short-term micro-management drives decision-making process
because of distrust between Government and industry.
a. How do we reconcile: assurance from Government to industry: for
Government to implement consistent long-term policies that work,
versus assurance from industry to Government: that industry will
deliver solutions that work? Unless we are really clear about
reconciling and balancing the need for the former with the need for the
latter, we will not know what we can technically do if we have the will to
achieve it.
b. How do we build a market system that starts to account for and
incorporate external costs and benefits as part of the total value
equation; and, furthermore, Government must take responsibility for
leading the sustainable development of New Zealand’s energy future.
c. How well do we manage and utilize our energy resources, and how
can we do it better? What do investors need for sustainable energy
development to become a practical reality?
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
Ref. Key Conclusions
C5 Current decision-making framework is inadequate for developing
a consensus amongst Government and industry stakeholders to
take appropriate action to address sustainable development of
the electricity sector.
a. Government agencies want views and opinions of energy market /
industry stakeholders to be expressed and presented with concrete
evidence-based facts and case studies for proposals for making
changes, taking action etc. It is evident that the existing processes
used to collect this information are not achieving the desired results to
address present Government needs.
b. Proper discussion and consideration of individual submissions from
members of the public and industrial organizations is not possible
because Government agencies do not have the expertise or the
resources to properly consider and assess all the options put forward.
c. Submissions are not coordinated and expressed in such a way as to
effectively address integrated industrial and public concerns of different
electricity market shareholders: responses are fragmented and
contradict one another – confusing the primary concerns and needs
addressed from lesser secondary concerns and interests.
d. Lack of coordination amongst various ministries and government
agencies has made it difficult to move forward with a cohesive strategy
for tackling current electricity market needs. There are no clearly
defined boundaries or guidelines for linking the various responsibilities,
interests and policy objectives of separate agencies and ministries into
a unified cohesive framework or plan that links New Zealand’s
sustainable economic growth and prosperity with its security of energy
supply.
e. Government needs policies that are: “long(-term), loud and legal”.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
Ref. Key Conclusions
C6 Insufficient vision and uncoordinated focus, fragmented scientific
and technological research, and inadequate human and financial
resources are preventing significant economic benefits being
derived from sustainable energy.
a. “Think Global, Act Local”. New Zealand Inc. needs a clear vision:
e.g. “New Zealand completely self-sustainable in energy resources by
____?”. If you provide a stable infrastructure environment that people
are confident in remaining stable, reliable and dependable for a long
period of time, with long-term hedge-type products with reliable
investment and pricing indicators that people can start banking against,
then the other stuff will follow. E.g. the Orion Networks pricing model
for investing in distributed generation. The same thing is observed with
transport infrastructure investments. We must have a stable long-term
focus.
b. Universities, Crown Research Institutes and other academic
institutions need to work much more closely with industry to facilitate
more effective commercialization of research, and ensure research
funding / investments are relevant to developing and improving the
industrial capabilities required to realize the market benefits possible.
c. The group of shareholders using and benefiting from distributed and
other sustainable energy resources do not necessarily represent the
same group of investors needed to facilitate their adoption. This
problem can be resolved if the distribution networks are given /
possess the technical capability, the financial capacity, the cooperation
and support of the public at large and local communities (beneficiaries
/ recipients of the services provided), and most importantly of all: the
will and clout of the political establishment to support: business
investment, R&D funding, long-term incentives, efficient and effective
rules and regulations etc. to make it all work.
d. In order to work out these issues, a research institute that addresses
the technological, political, commercial and legal issues should be set
up to facilitate and coordinate the reliable and useful adoption of
sustainable distributed energy resources through the lines companies,
and plot the smooth transition of New Zealand’s energy industry
towards delivering a long-term sustainable, secure and competitively
priced energy infrastructure that meets the needs of New Zealand Inc.
for generations to come.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
Ref. Key Conclusions
C7 Government needs to establish a Leadership Task Force of
people who know how the whole electricity system works and
how to effectively incorporate distributed energy resources for
optimum operating efficiency, reliability and security of supply.
a. Government policymaking for the electricity industry is a rudderless
affair. There are too many disparate parties attempting to steer
electricity policy in different directions. Lack of coordination is
responsible for much confusion.
b. There is significant overlap and hence confusion regarding the roles
of different yet similar political / governmental agencies competing for
influence and resources.
c. Government and industry must take a more hands-on approach
towards maintaining and developing New Zealand’s energy
infrastructure and untapped energy resources – including new /
improved load management strategies, smart metering and distributed
renewable energy resources.
d. Government and industry must take a more hands-on approach
towards improving the reliability and security of delivering New
Zealand’s energy requirements today and for future generations.
e. Greater integration and proactive coordination of industrial and
economic development policy with energy security policy and
environmental protection policy required.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
3. Action Points Raised
From the key conclusions (C1 to C7) and issues raised / specific needs
identified by participants, a list of action points are proposed. A1 to A4 are
derived from C1 to C7 and A5 to A6 have been drawn from the workshop
proceedings.
Proposed
Ref. Issues Action Points
Participation
A1 Support long-term • Long-term contracts for Energy
planning. energy supply and demand Minister;
required. Electricity
a. Long-term needs not Commission;
addressed by short-term • Pricing arrangements MED;
political agendas. (C1) should deliver long-term Commerce
contractual arrangements Commission;
that help new investors get Energy Users;
established and give Generators;
consumers who put a Retailers;
premium on security, T&D
contractual certainty. Networks.
A2 Constructive stakeholder • Views and opinions of Energy
cooperation. energy market / industry Minister;
stakeholders need to be Electricity
documented and presented to
a. Untapped potential for Commission;
the MED, Electricity
sustainable development Commission, Commerce MED; MfE;
due to fragmented markets. Commission and other NZTE;
(C2) Government ministries and Climate
agencies. Change
b. Many opportunities Office;
missed or lost due to lack of • Responses to Government Office of the
coordinated planning Requests for Information Parliamentary
between Government and (RFIs) should provide Commissioner
industry stakeholders. (C3) concrete, evidence-based for the
information; and, specific
Environment;
proposals for making
c. Short-term micro- changes, taking action etc. Commerce
management drives should be given where Commission;
decision-making process possible. Energy Users;
because of distrust between Generators;
Government and industry. • Government needs to be Retailers;
(C4) informed by stakeholders T&D
about problems associated Networks.
with regulations and policies
affecting the operation,
efficiency and effectiveness of
the electricity and energy
markets.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
Proposed
Ref. Issues Action Points
Participation
A3 Effective decision- • Chains of command, Energy
making framework. accountability and Minister;
communication need to be Electricity
a. Current decision-making improved within and amongst
Commission;
framework is inadequate Government structures.
MED;
for developing a Commerce
• A more robust, transparent
consensus amongst and technically-qualified Commission;
Government and industry decision making process is Energy Users;
stakeholders to take necessary. Generators;
appropriate action to Retailers;
address sustainable • Industrial stakeholders must T&D
development of the be engaged collectively by Networks.
electricity sector. (C5) Government in such a way that
interaction amongst different
b. Government needs to organizations is supported and
establish a Leadership enhanced to achieve better
results.
Task Force of people who
know how the whole • Acquire timely information,
electricity system works and the management of that
and how to effectively information, with appropriate
incorporate distributed smart metering technology.
energy resources for
optimum operating • Adopt Area and Time Specific
efficiency, reliability and Marginal Capacity [ATSMC]
security of supply. (C7) cost programmes.
A4 Concentrate resources to • Restructure R&D investment Energy
achieve a specific so that it supports NZ Inc., and Minister;
outcome. a common long-term vision for Electricity
New Zealand’s sustainable Commission;
a. Insufficient vision and economic growth and
MED; MfE;
prosperity.
uncoordinated focus, NZTE; R&D
fragmented scientific and • Create a guiding industrial- organizations;
technological research, Governmental coalition with Academia;
and inadequate human the resources needed to Climate
and financial resources are achieve the vision developed. Change
preventing significant Office;
economic benefits being • Empower broad-based action, Parliamentary
derived from sustainable by getting rid of the obstacles Commissioner
energy. (C6) and structures that undermine for Environ.;
the vision created.
Local govt.;
• Encourage risk taking and Chambers of
innovation by visibly Commerce;
recognizing and rewarding the Commerce
organizations that make a Commission;
difference towards progressing Energy Users;
the vision’s outcomes for New Generators;
Zealand. Retailers;
T&D Networks
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
Proposed
Ref. Issues Action Points
Participation
A5 Encourage greater • Support the development Energy
diversity of supply and of distributed energy minister;
demand to reduce risks. resource portfolio business Banks and
investment tools and other lending
a. A well-structured, models. institutions;
diverse portfolio of Business
distributed energy (supply- • Encourage banks and investors and
& demand-side) resources, other lending institutions to owners;
that can balance provide the equivalent of R&D orgs.;
fluctuating loads with revolving home loan MfE; Climate
fluctuating weather accounts for distributed Change
patterns, is needed for energy resource project Office;
long-term investment. finance. Electricity
Commission;
• Support collaboration MED; NZTE;
between business / project Generators;
investors and load / Retailers;
renewable energy T&D
forecasters to develop Networks.
acceptable & reliable
financial risk management
metrics.
• Ensure coordination of
energy investment signals
with energy and capacity
pricing signals, and energy
and capacity usage.
A6 Ensure multi-stakeholder • Government intervention is Energy
benefits derived from required to reconcile Minister;
new energy investments benefits derived from Electricity
cover their costs. investing in energy supply- Commission;
and demand-side products, MED; Project
a. Economic and other processes and services, Investors;
benefits derived from with the costs borne by Commerce
investing in distributed project investors. This Commission;
generation and demand means energy and capacity Energy Users;
side management are not benefits obtained by energy Generators;
readily realized by the wholesalers, retailers, T&D Retailers;
project sponsor or system networks, insurance firms T&D
operator. etc., recompense part of the Networks.
investor’s project capital
and operating expenditure,
as applicable, by law.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
4. Workshop Summary
ISSUES SPECIFIC
PRESENTER MAIN POINTS
RAISED NEEDS
• Historically, the ‘Planning Division’ definition of ‘reliability’: enough plant and fuel • Long-term • Can the
available to meet 7% more than normal load in a winter where lake inflows had been contracts for industry
85% of the mean. energy supply provide the
required. reliability NZ
• Historically the ‘Electricity Division’ definition of ‘reliability’: based around maintaining needs?
frequency and voltage through a centrally coordinated generation and transmission • Pricing
Alan Jenkins system operated to defined engineering standards. arrangements • Who pays for
should give R&D?
(Electricity • The new market structure has created the view: ‘the market will provide’, overlooking local
Networks the need to plan ahead. Consequently, focus is on creating an environment for generation as • Can CPI-X
Association) competition to flourish, not on delivering reliability. well as more deliver an
remote economically
Presentation: • In the interests of creating a flat commercial playing field, NZ has tended to have a generation sustainable
transmission-centric system. options a network
What is Reliable reasonable infrastructure
Firm Power • Transmission nodal pricing is one manifestation of possessing a transmission-centric chance of for NZ’s future
Capacity? Why system. succeeding. energy delivery
Do We Need it? reliability
• People don’t like building power stations near a local node, because even a relatively • Pricing requirements?
small volume of new generation there will mean that the price of power from remote arrangements
competing stations plummets. The net result: no significant investment, either in plant or should keep
long-term contracts. old, back-up
power stations
• NZ’s deregulated electricity market is operationally-focused on generation and nodally- in reserve for
driven by trans-mission. when things go
wrong, or
• It is not clear how much customers are willing to pay for reliability, and who should pay demand gets
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
for what within the mix of customers. ahead of
supply.
• Between 1992 and 1998, network companies were very focused on supply security,
and providing two-thirds of the new capacity being built at that time. The state was no • Pricing
longer carrying the responsibility for building power stations, and new stations were arrangements
actually being built close to loads. should ensure
that the parties
• The Bradford reforms of 1998 brought an end to this era, heavily influenced by a belief selling
that the networks’ involvement in generation was occurring because local monopolies electricity are
were imprudently building generation capacity that the country didn’t need – leaving selling a
local consumers to carry the cost through inflated lines charges. package that
includes
•The Bradford Electricity Reform Act of 1998 was driven by the belief that it would defined,
‘ensure that costs and prices in the electricity industry are subjected to sustained minimum
downward pressure”. reliability levels.
• Since 1998: distribution and transmission prices have decreased by: 10%. • Pricing
arrangements
• Since 1998: energy wholesale prices have increased by: 45%. should give the
parties who are
• Since 1998: total energy retail prices have increased by: 18%. best equipped
to put
• As a result of the 1998 reforms: there is a ban on networks trading in energy hedges. commercial
pressure on
• As a result of the 1998 reforms: there is a ban on exercising any sort of influence over transporters
a generation subsidiary, which must be managed through its own officers, with its own responsibility
board. for paying
transmission
• The Electricity Commission was established to address problems of: and
- security of supply; distribution.
- transmission losses;
- grid capacity constraints; • Pricing
- no liquidity or transparency in forward wholesale electricity prices; and, arrangements
- limited competition emerging / occurring in generation and retail. should
incentivise
• If network companies were investing in generation it would help Government and the consumers to
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
Electricity Commission achieve their objectives. make a
contribution to
• After the 1992 crisis, electricity system operations were working around a hydro reliability.
‘minizone’ (storage availability) to decide when, and if, back-up capacity is needed. Do
we need to revert to these centrally imposed security arrangements? • Pricing
arrangements
• There are not effective contingency plans in place to keep old, back-up plant available, should deliver
as a consequence of constructing the electricity market in the mid-1990s around spot long-term
nodal prices without any imposed longer term pricing arrangements such as loss of load contractual
probability payments. arrangements
that help new
• Existing network-level regulatory signals are very poor at dealing with supply reliability investors get
problems. The Commerce Commission’s price control formula linking volumes established and
distributed and allowed income deters: a. energy conservation and b. uptake of give consumers
distributed generation options that take load off parts of their systems (source of who put a
revenue). premium on
security
• Bad signals from the regulatory regime also disincentivise spending on research and contractual
development. The CPI-X thresholds only allow R&D expenditure to come out of profits certainty.
and under no circumstances be passed through to consumers.
• The annual minus-X adjustment erodes network profits and gives them the same
immediate, operational focus that dogs the wholesale electricity market.
• Does New Zealand need a major power crisis resulting in a substantial economic
recession to get reliability back firmly on the policy agenda?
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
ISSUES SPECIFIC
PRESENTER MAIN POINTS
RAISED NEEDS
• For Lines Companies to comply with Part 4a of the Commerce Act defining thresholds • If a subjective
for declaration of control of lines businesses: they must demonstrate no material process is used
deterioration in reliability to define an
“extreme
• SAIDI/SAIFI thresholds screening mechanism – are used to identify breaches that may event”, why use
warrant further investigation. an objective
mathematical
• Businesses may avoid post-breach inquiry if they demonstrate: Breach due to an process to
extreme event. analyze it?
• Views and
• What is an extreme event? Definition from the Assessment and Inquiry Guidelines: opinions of • The existing
Rodney Doyle
“Where one or a small number of rare but high impact events has a significant and energy market / process
material impact on a business’ reliability performance”. industry proposed for
(Commerce
stakeholders to handling
Commission)
• Difficult to use meteorological definitions of extreme events. Extreme weather limits are be expressed extreme events
location specific, open to argument, and Extreme events may not be meteorological. and presented cannot make
Presentation:
to the decisions fast
• Extreme events are self-defining. Key requirements for defining a measure Commerce enough to
Extreme Events
to identify extreme events: Commission. address the
needs raised.
Consistency – Applicable to all networks large or small, urban or rural.
• Priority is to
Efficiency – Clear classification of normal and extreme data. encourage best
practice in
Practicality – Should facilitate metric setting. outage
mitigation,
Suitability – Should use readily available data. supply
restoration and
Simplicity – Easy to understand and apply. network design.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
There-fore
• Steps to identifying an extreme event: proposal aimed
at improving
1. Collect up to five years of historical outage data existing
practices more
2. Calculate natural log of daily SAIDI figures. than providing
an effective
3. Calculate alpha (α) (mean of the log values). method for
dealing with
4. Calculate beta (β) (standard deviation of the log values). real-time
operational
5. Formula for an extreme event day boundary: requirements.
Focus is on
e(α + 2.5 β). reducing
problems and /
• If an extreme event is identified: or improving
responsiveness
Exclude data for extreme event days from SAIDI records. to current
problems.
Calculate average daily SAIDI of residual (last 5 years).
• Extreme
Substitute extreme event days SAIDI figures with average. weather events
are very difficult
Calculate new annual SAIDI figure. to anticipate
from historical
Test if threshold is exceeded. data, weather
patterns and
Decide on action. the shear
complexity of
• Need consistent reporting practices from lines businesses; Standardised reporting the statistical
information for those in breach; Issues in reporting of “Step” restoration type models (and
interruptions; hence their
Appropriate allocation of outage cause; Evidence of extreme events to be notified to reliability)
Commission a.s.a.p. to facilitate investigation and decision. involved.
• The Commerce Commission recognise the geographic diversity; • Conclusion:
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
Distribution businesses should still identify best practice: outage mitigation, industry is very
supply restoration procedures, and network design; Aim of improving overall service nervous and
reliability. wants to be
heard over the
Commerce
Commission’s
proposed
thresholds
regime.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
ISSUES SPECIFIC
PRESENTER MAIN POINTS
RAISED NEEDS
• Electricity Commission (EC) responsible primarily for: • Wide range of
possible
- overseeing electricity industry and markets. options and
- ensuring dry-year reserve. alternatives to
- Conducting electricity efficiency programmes; and transmission
- regulating Transpower. upgrade in the
Akld region
• Transpower proposes Grid Upgrade Plans (GUPs) to EC. Focus: 400kV Whakamaru- have been
Otahuhu transmission upgrade. considered.
Robert Reilly
Options
(on behalf of Roy
• EC involved because: favoured
Hemmingway)
include:
- Load in Auckland is growing. building surplus
(Electricity
- A solution needed to meet demand at peak times by about 2010. capacity into
Commission)
- Transpower requires EC approval to be able to pass costs of investment on to existing
its customers. proposed
Presentation:
- EC must decide if Transpower’s proposal is best solution. Assessment includes solutions to
application of GIT. address future
Alternatives to
- EC must ensure other options have been analysed, including generation and needs and
Transmission
demand-side alternatives. reduce overall
costs, and
• Generation options considered: incorporate
small
- G1: Baseload co-generation (84MW co-generation at Marsden by 2010.) intermediate
- G2: Baseload coal generation (320MW coal generation at Marsden by 2010 and investments to
320MW additional coal generation at Marsden by 2016.) buy time (defer
- G3: Baseload gas generation (385MW CCGT at either Rodney or Otahuhu by investments)
2010 and 2 x 200MW gas generators in Auckland by 2010, and 400MW CCGT
at either Otahuhu or Rodney by 2015, and 400MW CCGT in South Auckland by
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
2025.)
- G4: Wind generation (75-150MW of wind generation in Auckland region by
2015.)
- G5: Relocation of Whirinaki (155MW Whirinaki re-located to Auckland by 2010.)
- G6: Peaking plant (Peaking diesel generation in Auckland by 2010.)
- G7: Alternative technologies (200-250MW of emerging generation technologies
from 2015.)
• Demand-side alternatives considered:
- D1: Interruptible load (IL) (Up to 200MW of IL by 2010.)
- D2: Distribution Network Load Management (DNLM) (130-245MW DNLM by
2015 and 15MW ripple control replacement by 2010.)
- D3: Energy substitution (70MW gas substitution in Auckland by 2015 and 1-
22MW solar water heating from 2015.)
- D4: Energy efficiency measures (Range of measures including 25MW
residential lighting by 2010, 17-63MW residential heating by 2015, and 25MW
commercial measures by 2015.)
• Transmission alternatives:
- T1: duplex the WKM-OTA 220kV A and B lines, then install 400kV between
WKM and OTA in 2021.
- T2: install 220kV between WKM and OTA in 2017.
- T3: install HVDC between WKM and OTA in 2017.
- T4: install 400kV between WKM and OTA in 2017.
• Next steps:
- Assessment of ‘short short-list’ of alternatives (generation, demand-side, and
transmission) by applying GIT (now underway).
- Comparison of short-listed alternatives and Transpower’s proposal (Jan 2006)
- Draft decision on Transpower’s proposed 400kV project (Feb/Mar 06)
- Consultation (Mar/Apr/May 06).
- Final decision (Jun 06).
Page 22 of 67

Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
ISSUES SPECIFIC
PRESENTER MAIN POINTS
RAISED NEEDS
• Lines companies can own: Non renewable generation up to 50 MW or 20% of lines • Advanced
capacity. metering
provides value
• Lines companies can own: Unlimited new renewable generation (e.g. wind). for managing
existing and
• Lines companies can own: Reserve generation contracted to Electricity Commission. new energy
options more
• Capacity above 5MW or 2% is subject to arms length restrictions. effectively –
Submissions
who is
Gareth Wilson should provide
• Lines companies also prevented from trading in electricity generally and buying and investigating
concrete,
selling hedges. these
(MED) evidence-
opportunities?
based
• Exemptions from some or all of the restrictions may be granted on a case by case Where is the
Presentation: information;
basis. funding to
and, specific
research how
Facilitating proposals for
• Restrictions in place to minimise the opportunity and incentive for lines businesses to: new
Investment in making
inhibit competition; and/or technologies
Generation by changes, taking
cross-subsidise generation and retail activities. can improve
Lines action etc.
the operation of
Companies should be given
• Should arms length rules be relaxed? the electricity
where possible.
market?
- Should the capacity threshold be raised?
- What rules should apply to generation connected to another line owner’s • No research
network? has been done
on whether the
• Should the legislation explicitly set out criteria for exemptions? market
structure we
• Should lines companies be able to trade in hedges? If so, to what level? now have is
appropriate.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
• How could legislative uncertainty be reduced?
• It is not clear
• Discussion paper to be released March 2006 for comment from relevant stakeholders. how the various
government
departments
and agencies
are
coordinating
their activities,
let alone
cooperating to
achieve an
integrated
cohesive
electricity
market
development
and
management
strategy.
Page 24 of 67

Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
ISSUES SPECIFIC
PRESENTER MAIN POINTS
RAISED NEEDS
• The EC is responsible for: ensuring that electricity is produced and delivered to all • Small scale
classes of consumers in an efficient, fair, reliable, and environmentally sustainable generation only
manner; and, promoting and facilitating efficient use of electricity. gets value for
capacity from
• Key outcomes: separate
agreements
- Investment in (distributed) generation, transmission, energy efficiency and with distribution
Robert Reilly demand-side management. networks –
• Electricity retailers do not
(Electricity Commission value capacity
- Remove barriers to distributed generation.
Commission) wishes to be delivered.
informed about
- Access to lines for distributed generation.
Presentation: problems • The cost of
associated with installing export
- Arrangements for the sale of surplus small scale generation.
The Electricity the model meters could
Commission’s arrangements be a barrier to
Role and - Switching and reconciliation of small scale distributed generation. for the sale and DG uptake.
Distributed purchase of
Generation • The Government proposes to introduce regulations prescribing reasonable terms and surplus
conditions on which line owners and electricity distributors must enable generators to be • Separate
electricity. agreements are
connected to distribution lines.
needed with
• The objective is to facilitate the use of distributed generation by ensuring that it does the retailer and
not face undue barriers in connecting to lines. the distributor
to gain full
value from
• The Electricity Commission will have responsibility for administering the regulations
operating DG.
and for proposing amendments as required.
• The Electricity Act 1992 provides powers to regulate terms and conditions for the
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
purchase by retailers of small surpluses of electricity from generating units owned or
operated by consumers.
• It can be difficult for owners of distributed generation units to negotiate terms and
conditions with local retailers to purchase small surpluses of electricity generation.
• The Government would like to see this barrier to the development and uptake of
distributed generation reduced by setting appropriate terms and conditions for purchase
of small electricity surpluses by local retailers.
• The Government envisages that this policy should apply to consumers with generation
units capable of generating up to 40,000kWh over a year.
• A key principle however is that retailers should not incur ongoing financial losses by
the requirement to purchase such electricity.
• The Commission should seek to develop non-regulatory arrangements to achieve
these objectives, but should recommend regulations or rules if voluntary arrangements
are unsuccessful in achieving the policy outcomes the Government seeks.
• The Commission has a role in facilitating Distributed Generation.
• Model Retail contracts have provision for the sale and purchase of surplus electricity
from small scale generation.
• Existing rules do not prevent retailers from trading small scale generation.
• Proposed rules will facilitate trading and switching of the output from small scale
generation.
Page 26 of 67

Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
ISSUES SPECIFIC
PRESENTER MAIN POINTS
RAISED NEEDS
• Load management is useful when aggregated – due to scale and diversity. • Purchase of
cheap
• Demand-side is the ability for customers to effect an outcome on the electricity system controllable
/ market. load (from
customers) is a
• Load management involves an agreement with a customer to turn off a nominated big opportunity
appliance or replace dependence on the network for an agreed duration. for lines
companies to
• There are a variety of historical technologies in place. Future ability and scope is increase
Duncan Head growing with convergence of communications and energy infrastructures. network asset
management
(Vector Networks • Demand-side participation is not a “public good”, and it depends on the consumer’s • Coordination efficiency and
Ltd.) choice between price and quality. It is left to value-seekers to incentivise uptake. of energy economic value
investment – but load
Presentation: • Demand-side has many valuing-adding applications: signals with management
energy usage solutions must
Mass Market - Transmission: congestion relief, alternatives, emergency management. required. provide value
Load Control - Distribution: capital deferment, asset utilization. to all
Issues - Customer: transmission pricing, load management (under time of use pricing). stakeholders in
- Retail/Generation: energy hedging, portfolio & risk management. the value chain.
- Other: energy hedging, spot market influence, compliance management,
ancillary energy market services (e.g. voltage, under frequency). • Issues for
effective load
• It is doubtful whether any real long-term benefit is provided by the Transmission Pricing management
Methodology (‘TPM’). include: gaining
benefit from the
• Controlling to TPM targets can bring forward investment in distribution network without transmission
minimizing Transmission build. pricing
methodology
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
• Ability to reconcile actual benefits to third parties limiting demand-side application to including
non-distribution users. reconciling
peak load
• Alignment of basic building blocks will enable value of demand-side to be realized. reductions with
GXP price
• Load management needs to create value for those involved. reductions
(current
• An integrated system is required to gain network benefits from load management. difficult).
• Specific outcomes for network distribution load management are: network • An integrated
management, asset deferral, and satisfactory customer price-quality trade offs. system is
required to gain
• Focus on reducing numbers of customers on traditional controlled appliances through network
fuel substitution and personal choice. benefits using
SCADA
• Technology will change the current network load management paradigm. technology.
• Vector Networks is currently embarking on a significant rethink of load management. • Vector is
looking to
• Vector Networks is looking to review incentives for customers to participate in demand- review
side management, and how they participate. incentives for
customers to
• Vector Networks is looking at reducing free riders, so that demand-side benefits go participate in
where they are created. load
management
• It is essential to be able to recognize value (created by demand-side participation etc.) options.
and to be able to pass it on.
• Load
• Change in technology creates opportunities to establish next generation demand-side management
systems and strategies, so that ripple plant’s days and historical ownership structures needs to create
may be numbered. more value for
those involved.
• Ripple-relay
control systems
act like a
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
‘sledge
hammer’ – no
longer
appropriate for
managing
loads
effectively.
• Transmission
pricing does
not reflect
system peaks.
Page 29 of 67

Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
ISSUES SPECIFIC
PRESENTER MAIN POINTS
RAISED NEEDS
• Technical issues associated with installing network-embedded DG include: Connection
Arrangements; Protection;
Over and Under-voltages;
Stability; Auto Re-closing;
• The option of
Ferro-resonance; Metering; Islanding; Current Flows; Power factor; Under Frequency
separating
Protection; Harmonics.
electricity
Brent Noriss
generators and
• Commercial issues associated with installing network-embedded DG include: • Market rules
retailers in the
(The Lines Recovery of Costs including Engineering; Transpower Avoidance Calculations; Loss required to
NZ electricity
Company) Factor Calculations; Power factor; support the
market might
Dedicated Assets; Connection Contracts. complexity
make it harder
Presentation: associated with
to address the
• Industry issues associated with installing network-embedded DG include: Electricity connecting
technical
The Market ability to handle complex Distributed Generation Situations; Innovative Network distributed
issues
Experiences of Solutions; and, Plant Reliability. generation to
associated with
a Network networks in
installing and
Engineer in The • DG is exciting but involves a lot more engineering than most people realize. reality.
operating
King Country
network-
• There is significant difficulty in getting the various stakeholders to understand the
embedded
issues (let alone work together to address them!)
generation.
• It is not clear who is going to pay for what with DG installations and operations, let
alone ensure that sufficient benefit is concentrated in few enough hands to justify project
commencement.
Page 30 of 67

Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
ISSUES SPECIFIC
PRESENTER MAIN POINTS
RAISED NEEDS
• Eastland Networks Limited (ENL) has commercial and operational motivations for • Transpower’s
investigating DG. plans to
upgrade
• ENL network characteristics include: low consumer density, low average consumer existing circuits
consumption, fed by a long radial transmission line with high nodal energy prices. is limited
considering
• Capacity is a key issue with 47MW uncontrolled and 39MW+ controlled. There is a forestry trends
single line, double circuit 110kV line, running through rugged erosion prone back- and the growth
country. in regional
Matt Todd
processing and
• A well-
• The transmission assets are becoming n-1 constrained. log exports.
(Eastland structured,
Networks) diverse
• 38MW per circuit during the summer. • ENL needs
portfolio of
non-
Presentation: distributed
• Peak consumption could grow to 80MW by 2011. transmission
generation
solutions that
Maximising required to
• Price is a key issue affecting the network: large customers have been paying 4 to 7 will address
Value from make it (DG)
c/kWh, new contracts (3 years) are being offered at 10 c/kWh. energy delivery
Distributed work.
prices and
Generation
• For forestry processing energy is a top 3 input cost. capacity
constraints.
• Investors in the region planning new developments need certainty around energy:
price, supply (capacity) and contract terms (of supply / price). • The current
electricity
• Typical problem / challenge involves: investing in a forestry processing plant with a 25 regulatory
year $100m investment to make, where energy is one of its top 3 input costs, and environment
energy has risen 30% over the last 3 years, with a maximum forward (hedge) term of 3 does not
to 5 years. provide
incentives for
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
• Investors need forward certainty to invest. lines
companies to
• Possible solutions include: upgrading the transmission line and adding a third circuit get involved
and a new GXP, but increased transmission capacity does not address the price. with energy
efficiency and
• Non-transmission solutions can address both the capacity and the price: e.g. demand side
management.
- Increased demand side management and energy efficiency measures.
- Installation of Distributed Generation. • Forest residue
- Distributed Generation is seen as a portfolio of relatively small scale generation is a potential
(sub 50MW) that provides surety of supply through diversity. source of
- DG can address the capacity issue. energy,
- DG can address the price issue. capable of
- DG can help facilitate greater investor confidence. deferring lines
upgrades, but
• Demand side management provides better use of controllable load, and load shifting needs a large
from on-peak to off-peak. heat load to
justify
• It is not possible to recover lost revenue from greater efficiency due to demand side financially.
management.
• There are opportunities for larger industrial customers to shift load.
• Significant network constraint on the Mahia Peninsula 2 two months of the year over
the summer when a 1MW diesel generator is operated. At the moment there are 800
ICPs, and another 500 ICPs are on the WDC plan.
• DG provides capital deferral, reduces transmission requirements, improves network
performance, and provides a sustainable local supply.
• Biomass forestry residues provide hundreds of thousands of tonnes of wood waste per
year of potential fuel.
• Waste gas is available in Gisborne as a low cost fuel.
• Co-generation gas is very attractive for process heat applications if long-term
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
ownership and contract issues can be resolved.
• Hydro has huge appeal if supply variability, soil erosion, resource consents and large
front-end capital investments can be handled.
• 6 x 1MW diesel generators are installed to reduce Transpower connection charges,
defer capital expenditure, improve network performance, sell energy output, and gain
value from improved network performance (e.g. CPI-X). The downside is that running
times are increasing and so are fuel costs.
• Coal has major environ-mental and economic costs to consider. It also needs o be
large scale (150MW+ to make it worthwhile). Also carbon tax penalties to consider.
Furthermore, transmission capacity is not able to cope with this scale.
• Wind energy has several benefits: it is environmentally friendly, unlimited invest-ment
in wind by lines companies is allowed, its economic value is increasing all the time with
scale of production, technology improvements and escalating energy costs etc. There is
a large potential on the east coast. Several sites are currently being monitored.
• Several issues with wind involve: finding suitable wind resource, dealing with low
capacity factors, unpredictable operating cycles, sale of wind energy output, economics,
visual and noise concerns, proximity of small sites to other infrastructure for delivery
purposes and consumption.
• The key to successful utilization of DG by ENL involves investing in a balanced
portfolio of DG: where key attributes of each type are utilized. E.g. a portfolio of hydro,
diesel, wind and biomass.
• Evaluation of current DG options for ENL reveal:
- Wind provides an immediate option.
- Hydro suffers from a lack of geography and hydrology to support sustained
storage limits.
- Biomass is a very viable option but difficult to coordinate
- Waste gas generation has limited potential.
- Coal is expensive, has scale issues and serious environmental concerns.
- Gas has an uncertain supply, high cost and lack of capacity is an issue.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
- Diesel is too expensive due to (increasingly) long running cycles.
• The Electricity Industry Reform Act restricts lines companies from managing an optimal
DG portfolio.
• Regulation makes it not possible to purchase hedges.
• Regulation is responsible for ‘arms length ruling’ and ‘corporate separation ruling’
limiting lines companies from selling their own electricity generation retail.
• Small scale DG will not be economic unless the EIRA is relaxed.
• Lines companies are by their very nature geographically located, asset owners with
strong balance sheets and low cost of capital. They are a logical and appropriate
investor in new generation.
Page 34 of 67

Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
ISSUES SPECIFIC
PRESENTER MAIN POINTS
RAISED NEEDS
• MainPower’s interest in DG is purely community-focus-ed. They are owned by their • MainPower
customers, and profits returned are distributed as rebates on the power bills. aims to be a
leading energy
• MainPower’s vision is to be a leading electricity and energy services business, services
committed to customer value and to the region’s prosperity. provider for the
region which
• MainPower wants to proactively respond to the energy issues facing their region. has a very high
growth rate, no
• No electricity is generated in the region, and $1 million leaves the region each week to current
Todd Mead pay for supply from generation elsewhere. generation, and
a wealth
(MainPower) • MainPower can use local wind, water and solar resources to generate energy. transfer of over
$1m per week
Presentation: • Hydro power is a perfect complement to wind, and MainPower is currently investigating out of the
small scale, minimal impact projects. region.
Renewable
Energy in North • MainPower has a number of pilot projects underway for micro-generation for homes • Community
Canterbury and and businesses, and is currently installing solar power and energy-conserving shading. support is vital
Kaikoura to support
• Using local resources to generate electricity will bring real benefits to the North existing and
Canterbury and Kaikoura communities, including: new alternative
energy supply
- a secure and reliable supply of electricity initiatives. Most
- regional economic prosperity support comes
- a better lines business (financial and operational management) from local
companies
• Significant benefits to the country as a whole include: motivated by
community
- a more diverse network and energy independence ownership and
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
- environmental gains from saved emissions sharing of
benefits.
• Next steps for MainPower include: wind monitoring, hydro feasibility studies, and solar
energy projects. Community support is considered vital to success.
Page 36 of 67

Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
ISSUES SPECIFIC
PRESENTER MAIN POINTS
RAISED NEEDS
• The pace of technological change usually precedes the pace of business innovation • Economic
required to accommodate the new (technologically-enabled) opportunities realised. benefits from
DG are
• Furthermore, the commercial market derived from the prevailing regulatory / legislative greatest when
environment is usually even slower to respond to the new business requirements lines
identified (to make the new opportunities work). companies are
involved. In
• Some businesses may encounter minimal resistance to creating new markets, simply fact, financial
Iain Sanders
because appropriate legislation has not been developed yet and regulations do not incentives from
exist: for example, the internet in its early days. distribution
(Sustainable
networks for
Innovative
• Other businesses however, may encounter stiff resistance to proposed market delivering DG
Solutions)
changes, especially if entrenched market positions of market incumbents are capacity can tip
threatened: for example, telecommunications and electricity. the balance so
Presentation:
that DG is
• There are several benefits from implementing better policies for managing electricity commercially
Energy &
assets: attractive if the
Capacity
technical and
Valuation for
- Improved stewardship and accountability regulatory
Three Different
- Improved communication and relationships with service users issues can be
Networks
- Improved risk management managed
- Improved financial efficiency effectively. Key
network
• Improved stewardship and benefits
accountability is achieved by: include: lines
upgrade
1. Demonstrating to owners, customers and stakeholders that services are being deferral, T&D
delivered effectively and efficiently. peak load
2. Providing the basis for evaluating and balancing service / price / quality trade- reduction, and
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
offs. standalone
3. Improving accountability for use of resources through published performance system
and financial measures. replacement of
4. Providing the ability to benchmark results against similar organizations stranded /
underutilized
• Improved communication network assets.
and relationships with service users is achieved by:
• Main
1. Improving understanding of service requirements and options. conclusion
2. Formal consultation / agreement with users on the service levels. drawn from IRL
3. More holistic approach to asset management within the organisation, through research into
multi-disciplinary management teams. economic
4. Improved customer satisfaction and organisation image. viability of
small-scale
• Improved risk management is achieved by: network-
embedded
1. Assessing probability and consequences of asset failure. generation: full
2. Addressing continuity of service. economic
3. Addressing the inter-relationships between networks (the chain is only as good benefit will only
as its weakest link) and risk management strategies. be achieved if
4. Influencing decisions on non-asset solutions through demand management. firm capacity
from network
• Improved financial efficiency is achieved by: alternatives can
be guaranteed.
1. Improved decision-making based on costs and benefits of alternatives. This is a major
2. Justification of all costs of owning / operating assets over the lifecycle of the technical issue
assets. for research to
address: e.g.
storage
alternatives,
fuel dispatch
strategies,
control systems
for DSM,
energy
efficiency etc.
Page 38 of 67

Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
ISSUES SPECIFIC
PRESENTER MAIN POINTS
RAISED NEEDS
• High network reliability is expected, essential, and must be maintained during load
growth, load stability and load decline.
• DG affects reliability in different ways: under load growth, load stability and load
decline; and through the intermittent availability of DG and the need / use of fuel-based
DG and CHP DG / fuel substitution.
• Distributed energy can reduce peak load demand by: load shifting and storage; energy
Alister Gardiner
efficiency; fuel / source switching; managing the local site demand, and/or export to the
distribution network.
(Industrial
Research)
• Other network-embedded generation issues include:
power quality, safety, stability, uncertain avail-ability, large numbers of small generators
Presentation:
difficult to control, may worsen the load factor, reduce grid energy delivered - worsening
supply economics.
Network
Reliability and
• Micro-scale distributed energy represents a vast untapped mass market of 1.7 million
Distributed
dwellings in NZ, plus a large number of small commercial users.
Energy –
Technical
• Micro-scale systems can be used: to supply residential and commercial general
Issues
customers (101PJ), be user-managed to generate “behind the meter”, deliver
intermittent or “dispatchable” (firm capacity), provide combined heat and power (CHP)
from delivered fuel.
• Micro distributed energy provides a higher source-to-service efficiency via combined
heat and power from fuels, and avoided transmission and distribution losses.
• Micro distributed energy provides increased energy supply resilience via distributed
“self-healing” systems, and micro-grids.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
• Micro distributed energy provides unobtrusive growth by: capturing renewable energy
(where minimal RMA issues), using small generators located on the premises –
including the use of existing built environment (rooftops), enabling incremental growth,
and facilitating network load expansion without (deferring) upgrading T&D.
• Micro distributed energy provides advanced opportunities for SMEs, e.g. opportunities
to develop and sell: SHW systems, inverters, fuel cell systems, storage and other
conversion technologies, and, control and communication systems / components.
Page 40 of 67

Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
5. Supplementary Feedback from Participants
Participants FURTHER POINTS RAISED
• Today, investment decisions [generation, transmission, distribution, metering, and load management] are being made
on short run marginal costing [SRMC] which lack, as a consequence, integrated planning.
• Both kW and kWh distribution losses should be valued at various time periods, and at the long run marginal cost
[LRMC] of supply from the bulk supply system. Many analysts undervalue these losses. Any reduction in transmission
and distribution kW losses during system peaks will lead to savings in generation and transmission capacity. Due to
poor metering, losses and customer loads are indistinguishable. It is much less costly to save kilowatts in transmission
capacity and kilowatt hours in energy by reducing distribution losses, than by other means. Reduced electricity costs
Brian Tolley can be achieved by improving consumer load factors coupled with improving network component and operational
performance.
Brian Tolley
Corporation Limited • Measurement and management of the whole electricity system needs to be undertaken. The key requirement is timely
information, and the management of that information, with a revision of back office software. Loss reduction can be
achieved and capacity needs decided with timely and accurate information.
• Debate on central versus distributed generation is the wrong way to analyse such major issues. Both forms of
generation are needed. Solutions will emerge when an ATSMC-type analysis involving transmission, distribution
network capacity, the age profile of assets and resource assessments, such as river and tidal flows, have been
analysed and are collectively considered. Included in this is the fundamental issue of using smart metering and
communications to undertake the correct research and analysis.
Brian Tolley
(see above) • T&D network, network component, metering and information supply performance evaluation research is required. To
continue with deemed profiling using inefficient and ancient metering (providing poor information quality), will, as
Alister Gardiner proposed by the Retail Market Advisory Group (RMAG) of the Electricity Commission, cause unnecessary costs,
Industrial Research incorrect investment, incorrect pricing and inefficiency. Area and Time Specific Marginal Capacity [ATSMC] cost
programmes proposed by EPRI, Industrial Research (submission to Ministry for Economic Development on “Facilitating
Iain Sanders Distributed Generation”) and other organizations provide the necessary tools. (See Appendix 6.3 and 6.4).
S.I.S. Limited
Page 41 of 67

Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
6. Appendices
6.1 Workshop Agenda
08:30 REGISTRATION
08:45-09:00 WELCOME ADDRESS, TONY PRICE, ACTING CEO, INDUSTRIAL RESEARCH LIMITED
SESSION 1: ELECTRICITY NETWORKS RELIABILITY ISSUES
09:00-09:30 What Is Reliable Firm Power Capacity? Alan Jenkins Chief Executive
Why Do We Need It? Electricity Networks Assoc.
09:30-10:00 System Reliability: Recommendations For Rodney Doyle Chief Advisor
Extreme Events Network Performance Group
Commerce Commission
10:00-10:30 Alternatives to Conventional Transmission Roy Hemmingway Chair, Electricity Commission
Upgrades
10:30-11:00 MORNING TEA
SESSION 2: LOAD MANAGEMENT OPTIONS FOR THE NETWORK
11:00-11:30 Facilitating Investment in Generation by Gareth Wilson Manager of the Electricity Gp.
Lines Companies Ministry of Economic
Develop.
11:30-12:00 Electricity Commission’s Role and Robert Reilly Senior Advisor, Retail
Distributed Generation Electricity Commission
12:00-12:30 Mass Market Load Control Issues Duncan Head Divisional Manager, Business
Development,Vector
Networks
12:30-13:30 LUNCH GUEST SPEAKER, BRENT NORISS, ENGINEERING MANAGER, THE LINES COMPANY
SESSION 3: DISTRIBUTED ENERGY IMPACTS ON THE NETWORK
13:30-14:00 Maximising Value from Distributed Matt Todd CEO, Eastland Networks Ltd.
Generation
14:00-14:30 Benefits Derived from Distributed Todd Mead Generation Development
Generation Manager, MainPower
14:30-15:00 Incentives for Embedded Distributed Iain Sanders CEO, Sustainable Innovative
Generation – Three Different Perspectives Solutions Ltd. (formerly of
For Three Different Networks Industrial Research Ltd.)
15:00-15:30 AFTERNOON TEA
SESSION 4: FORUM FOR DISCUSSING ISSUES AND ANSWERING QUESTIONS
15:30-16:30 Policy and Technical Issues Associated Iain Sanders Facilitator, Panel of Experts
with Distributed Energy Resources, the
Electricity Market reforms, and network
Reliability
16:30-17:00 Summing up, conclusions and close Alister Gardiner H&DE Platform Manager, IRL
and Iain Sanders CEO, Sustainable Innovative
Solutions Ltd.
17:00 CLOSE
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
6.2 List of Attendees
First Name Surname Position Organisation
Alan Jenkins Chief Executive Electricity Network
Association
Alister Gardiner H&DE Platform Industrial Research
Manager
Ben McQueen Project Manager Industrial Research
Brendon Quinn Network Manager Electricity
Ashburton
Brent Norriss Engineering The Lines
Manager Company
Brian Cox Director East Harbour
Services Ltd
Brian Tapp Marlborough Lines
Ltd
Brian Tolley
Bruce Geddes Power On
Cameron Parker Spot Trader Genesis Energy
Carmen Blackler Transmission Contact Energy
Manager
Chris Freear CEO NZ Windfarms Ltd
Dene Biddlecomb Chief Executive Horizon Energy
Distribution Ltd
Dennis Jones Orion New Zealand
Ltd
Don Lewell Engineering Horizon Energy
Manager Distribution Ltd
Doug Clover Environmental Parliamentary
Investigator Commissioner for
the Environment
Duncan Head Divisional Manager, Vector Networks
Business
Development
Erick Coenen Technical Support Genesis Energy
Manager
Gareth Wilson Manager of the Ministry of
Electricity Group Economic
Development
Gavin Bonnett Distributed Orion New Zealand
Generation Ltd
Gerry Te Kapa Coates Managing Director Wise Analysis Ltd
(wants info sent to
him)
Glen Thomson Manager Grid Transpower Ltd
Economics
Greg Skelton Alpine Energy
Iain Sanders CEO Sustainable
Innovative
Solutions
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
First Name Surname Position Organisation
Ian Shearer The Sustainable
Energy Forum Inc
John Huckerby Power Projects Ltd
Jon Morris Industrial Research
Kerian Byrne Marlborough Lines
Ltd
Kevin Stevens Industrial Research
Matt Todd CEO Eastland Networks
Mark Gatland Northpower Ltd
Michael Callandar Energy Efficiency
and Conservation
Authority
Mike Hearn Electra
Mike Parker Grid Economics Transpower Ltd
Lead Analyst
Mike Staines Industrial Research
Molly Melhuish
Murray Milsom Senior Project Rockgas Ltd
Engineer
Nalin Pahalawatha Team Leader Grid Transpower Ltd
Planning
Paolo Ryan Commerce
Commission
Ralph Sims Dir, Energy Centre Massey University
Robert Reilly Senior Advisor, Electricity
Retail Commission
Rodney Doyle Chief Advisor, Commerce
Network Commission
Performance Group
Roger Paterson PowerNet Ltd
Stephen Ward Strategic Energy East Harbour
Advisor Services Ltd
Todd Mead Generation MainPower
Development
Manager
Tony Price Acting CEO Industrial Research
Tristan Wallbank Suzlon Energy
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
6.3 Alternative Policy Frameworks for DG
(By Iain Sanders)
(Originally included as part of a submission by Industrial
Research to the Ministry for Economic Development on:
“Facilitating Distributed Generation”)
Introduction
The policy approach presented by Government in its DG Discussion Paper
[1], represents a rather reactive approach to DG facilitation by electricity
market incumbents. The justification for imposing DG regulations is that: “it
continues to be difficult to determine what are the likely requirements for
connection to the lines network, how costs are going to be shared, the nature
of the connection contract and the expected timeframe to conclude a contract”
[2]. Government can instead build on existing best-practice employed by
various stakeholders in the NZ electricity market, and develop this knowledge
base further – but as a result of taking the policy approach espoused in the
discussion document, a limited customer-driven, utility-response view of DG
facilitation has been created. There are three underpinning facts why this
approach is limited and will stifle both competition, and the growth of DG in
New Zealand.
Fact One: Greater direction (and hence control) of the application process for
issuing Resource Consents has been granted to local Councils [3]. Each local
Council has its own criteria and prejudices for assessing individual resource
consents. When the business interests and political agendas of Councils and
DG-operators/owners clash: e.g. in the case of Environment Canterbury
(ECAN) versus Orion Networks over fuel-driven DG emissions restricted to
peak demand periods, lengthy delays may result. Project Aqua is a classic
case of resource consent delays increasing project costs and delaying
revenue streams vital to its financial viability [4].
Fact Two: “Difficulties in obtaining long-term agreements to sell electricity to a
retailer or major customers have also impeded investment” [5]. Industrial
Research can attest to this fact through contact with various prospective and
existing non-retailer DG operators/owners. As a result, Industrial Research
knows of at least three vertically integrated generator-retailers in New Zealand
who resist / complicate attempts by independent DG producers to sell
electricity to them at a reasonable price [6]. Industrial Research described this
problem three years ago to the Ministerial Board of Inquiry into the Electricity
Market [7]. The problem still remains and in its present form, represents a
major impediment to DG facilitation in New Zealand. EECA has also
described “the lack of standard agreements for electricity retailers to purchase
surplus electricity” [8] as a barrier to developing the DG market in New
Zealand. At the moment, energy retailers favour power purchase agreements
with major customers whose business retention is worth more than any
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
inconvenience caused by accommodating the purchase of DG electricity
exports [9].
Fact Three: “Transmission and lines businesses are not obliged by necessity
to include the impact of network embedded and distributed generation assets,
or energy management and conservation measures on their network
infrastructures” [7]. As a consequence, personnel responsible for
infrastructure asset valuation, management and planning do not consider
outsourcing network capacity options. This is the main reason why a
customer-driven, utility-response will not create the market environment for
the DG industry to develop significantly in New Zealand. “Renewal accounting
of infrastructure assets for performance measurement derivation in
transmission and lines businesses, should clearly stipulate that energy
management and conservation measures, and network embedded and
distributed generators, must be valued on an equal basis with other
infrastructure assets. Equal status and financial weighting should be granted
to these other options in order to maximise the economic and environmental
sustainability and efficiency and reliability of new infrastructure asset
management plans, taking into account the latest technologies and
techniques” [7]. Until this is done, there will be very little incentive for lines
networks to support (let alone encourage) grid-connected DG delivering
capacity-support. For justification of this statement, take a look at the
alternative tactics adopted by different lines companies for hooking-up and
costing the interconnection of a Windflow wind generator to their networks
[10].
In order to promote effectively the connection of distributed generation (DG) to
distribution networks, appropriate standards, regulations and fair business
practices must be applied. The effectiveness of these procedures will
determine DG penetration in the New Zealand Electricity Market. Different
regulatory strategies will have a greater or lesser chance of succeeding,
depending on the legislative framework adopted for facilitating DG in New
Zealand. This paper looks at different legislative frameworks for tackling this
issue and how much impact they might potentially have on facilitating DG in
New Zealand.
Legislative Frameworks for Facilitating Distributed Generation
There are four successive legislative frameworks that can be adopted for
facilitating DG in New Zealand under the prevailing de-regulated electricity
market environment that exists. These frameworks in order of progression
are:
A. Customer-Driven, Utility-Response Framework;
B. Least-Cost Utility Asset Management Framework;
C. Utility-Driven, Customer Response Framework; and,
D. Temporal-Locational Market-Driven Framework.
Each legislative framework will be discussed briefly in order of progression,
building on the arguments presented in the framework preceding it.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
A. Customer-Driven, Utility-Response Framework
The market incumbents permit DG facilitation on their terms. Prevailing
energy supply and energy delivery rules dominate new regulatory
arrangements. The Status Quo is more or less defended / protected.
The Customer-Driven, Utility-Response framework follows the philosophy
underpinning the suggestions proposed in the Government Discussion Paper
(GDP) for facilitating DG in New Zealand [1]. The underlying assumption is
“that the (New Zealand) investment environment is one of flexibility which
should encourage investment in distributed generation that is seen as
commercially attractive” [11]. From our experience at Industrial Research, if
this were true, there should be a greater number of commercially viable DG
systems operating in the New Zealand market today. This is not the case
because of the lack of adequate disclosure of locational network capacity
costs. There are no technical or commercial reasons why many more DG
systems could not operate profitably in New Zealand today. This fact is borne
out by numerous publications that have been written on this topic by Industrial
Research over the past five years [12].
The primary focus of the Customer-Driven, Utility-Response framework in
facilitating DG, involves preserving the vested interests of electricity market
incumbents while minimising the risks associated with opening up the market
to new entrants. The responsibility lies almost entirely with new DG market
entrants to create and exploit opportunities that will lead to the establishment
of sustainable DG businesses / projects. This process involves the
prospective DG-owner / -operator initiating project proposals with various
market- / regulatory-stakeholders in order to secure DG-interconnection rights,
resource consents and power purchase agreements etc. The time-frame and
budget allowed for this process, must be sufficient to ensure that the financial
viability of the DG proposal is not compromised, if and when permission has
been granted for the proposal to proceed (and provided no additional costs or
time delays have been incurred).
No business worth its salt would bother to investigate DG investment
opportunities under this legislative framework unless they had prior knowledge
of the overall impact on their bottom line of potentially costly and lengthy
consultations with utilities and regulators – including arguments regarding the
technical and economic impact of DG on the lines network (and providing
adequate compensation to satisfy the parties involved). This represents a hit
and miss affair regarding the technical and financial feasibility of DG
proposals from a prospective investor’s perspective, and depends heavily
upon prior knowledge of the strengths and weaknesses of the electricity
supply and delivery infrastructure in the locality of the sites proposed. In many
cases, this information is not known, resulting in additional time and expense
for the lines network company to furnish the prospective DG investor with the
information to decide whether a business proposal is worth preparing (yet
alone pursuing).
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
Under this arrangement for facilitating DG, utilities will have to identify
potential DG interconnection sites for base, intermediate or peak generation.
Most likely the utilities will not have conducted interconnection studies for
these sites, but based upon current knowledge of general system conditions,
will at least select sites that are less likely to cause severe system impacts
and expensive network upgrades. Interested DG-operators will still need to
independently evaluate each site and assume all the risks should they decide
to install DG at one or more sites. Furthermore, any or all of the identified sites
may require appreciable network upgrades or may be otherwise unsuitable for
a variety of reasons. Accordingly, the utilities will not warrant or otherwise
guarantee the suitability of these sites for the DG-operator to locate new
generation on their systems. This represents considerable extra cost to any
prospective DG investor, on a project whose financial viability may be
marginal at best. This process alone could eat up any profit an investor stands
to make by proceeding with a ‘commercially viable’ project.
The complex nature of modern electricity planning, which must satisfy multiple
economic, technical, social and environmental objectives, requires the
application of a regulatory planning process that integrates these often-
conflicting objectives and considers the widest possible range of traditional
and alternative energy resources. The availability of timely and accurate
information on temporal-locational energy-capacity requirements is a
prerequisite to informed investor decision-making for facilitating DG – and the
basis for developing the three legislative frameworks described next.
B. Least-Cost Utility Asset Management Framework
Utilities are required to adopt and apply procedures that regularly consider
and compare DG opportunities as a valid least-cost alternative to conventional
wires and cables business operations. Information disclosure of these asset
management practices is required.
In New Zealand today, “Least-Cost Utility Asset Management” is not required
for planning lines network company operations or for managing their assets.
Basic Asset Management (BAM) practices – defined as the initial level
designed to meet minimum legislative and organisational requirements for
financial planning and reporting – are applied. BAM requires basic technical
management outputs such as: statements on current levels of service, forward
replacement programs and associated cashflow projections. BAM will not
optimise supply and demand-side investments and returns at the distribution
level, nor encourage a cohesive policy and business framework for including
distributed generation-demand response measures in utility asset valuations.
Advanced Asset Management (AAM) practices on the other hand, will achieve
“Least-Cost Utility Asset Management”, by optimising the activities and
programs required to meet optimum (agreed) service standards at minimised
lifecycle costs. The objective is to look at the lowest long-term cost (rather
than short-term savings) when making AAM decisions. AAM requires the
development of management tactics based on collection, analysis and
dissemination of key information on asset condition, performance, lifecycle
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
costs, risk costs and treatment options. Selecting appropriate AAM
requirements and standards for utility asset valuations will depend upon the
following criteria:
(1) Costs and benefits to the utility;
(2) Size, condition and complexity of the assets;
(3) Risk associated with failures;
(4) Skills and resources available to the utility;
(5) Customer expectations; and,
(6) Legislative requirements.
Legislative requirements is the most important criterion, defining the
parameters affecting the scope of all the other criteria. Appropriate legislative
requirements will benefit utility accountability, service management, risk
management and financial efficiency. These benefits are summarised in table
one below.
Table 1: Benefits from Better Legislation of Infrastructure Asset Management Practices
1. Demonstrating to owners, customers
A. Improved stewardship and and stakeholders that services are
accountability by: being delivered effectively and
efficiently.
2. Providing the basis for evaluating and
balancing service / price / quality
tradeoffs.
3. Improving accountability for use of
resources through published
performance and financial measures.
4. Providing the ability to benchmark
results against similar organisations.
1. Improving understanding of service
B. Improved communication and requirements and options.
relationships with service users by: 2. Formal consultation / agreement with
users on the service levels.
3. More holistic approach to asset
management within the organisation,
through multi-disciplinary
management teams.
4. Improved customer satisfaction and
organisation image.
1. Assessing probability and
C. Improved risk management by: consequences of asset failure.
2. Addressing continuity of service.
3. Addressing the inter-relationships
between networks (the chain is only
as good as its weakest link) and risk
management strategies.
4. Influencing decisions on non-asset
solutions through demand
management.
1. Improved decision-making based on
D. Improved financial efficiency by: costs and benefits of alternatives.
2. Justification of all costs of owning /
operating assets over the lifecycle of
the assets.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
A formal approach to the management of infrastructure assets is necessary to
provide services in the most cost-effective and technically efficient manner,
and to demonstrate this to customers, investors and other stakeholders. The
key to achieving major change in the emerging deregulated electricity market,
is to develop a cohesive policy and business framework for including
distributed generation-demand response measures in utility asset valuations.
The goal of appropriately legislated utility infrastructure asset management is
to meet a required level of service in the most cost-effective way through the
creation, acquisition, maintenance, operation rehabilitation and disposal of
assets to provide for present and future customers. The key is to develop a
cohesive legislative framework for including distributed generation-demand
response measures in utility asset valuations.
Infrastructure asset management and valuation issues influence DG
investments, through the creation, acquisition, maintenance, operation,
rehabilitation and disposal of assets to meet a required level of service. These
issues include: adopting lifecycle costing, developing cost-effective
management strategies for the long-term, providing a defined level of service
and monitoring performance, managing risks.
C. Utility-Driven, Customer Response Framework
Utilities develop the necessary tools to provide a consistent and thorough
assessment of DG load management and capacity-support benefits as part of
their regular business operations, and publicly disclose all the relevant
information, in a timely and accurate manner for independent prospective DG
investors / operators to respond.
The “Utility-Driven, Customer Response Framework” develops further the
concepts introduced for the “Least-Cost Utility Asset Management
Framework”. Distribution costs vary significantly between utilities and between
locations within utilities. Marginal costs also vary significantly by time of day
and year. Where, and when, marginal distribution costs are high, there are
often cost-effective opportunities for local DG to delay or eliminate the need
for distribution system investments. Utilities vary significantly in the degree to
which their existing data, planning processes, and analytical methods are
suitable for considering DG alternatives. Few utilities have a well developed
process for considering DG. Government legislation can significantly improve
this situation by taking appropriate measures to develop objectives and
strategies that oblige all utilities to adopt improved costing methods. Utilities
should be in a position to identify the best opportunities for implementing DG
projects, and encourage / discourage (as appropriate) independent DG
investments via incentives / disincentives derived from the underlying drivers
influencing the value or cost to the utility (table two).
The underlying drivers of value / cost described in table two, could be used to
inform prospective DG-owners / investors via appropriate information
disclosure and dissemination, of the temporal-locational costs or benefits
associated with any particular DG investment. In other words, sufficient
information should be supplied by the utility in order for the prospective
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
investor to make an informed choice about whether a DG prefeasibility study
for a particular site should proceed. Appropriate utility information disclosure
would have to be based upon improved costing methodology for electric
distribution planning [13]. The most important objectives and strategies for
improved costing methodology are summarised in table three.
Table 2: Underlying Drivers of Value / Cost
Driver Description
Many drivers of cost can be characterised broadly by
Location distinctions such as Remote vs. Urban, Constrained vs.
Unconstrained, and Mild vs. Extreme Climate.
The magnitude of the growth relative to capacity sets both the
Load Growth timing and the magnitude of action required, and with it scales
the magnitude and timing of investment. Customer-sited
generation growth will impact the load seen by the utility as well,
and may become an important element to consider in load
forecasting.
Distribution project alternatives that have time varying load
Load Shape carrying capability must correlate with the peak periods in order
to provide any value, so the load factor and peak timing have an
impact on net cost.
The vintage, performance, and specifications of the equipment
Equipment already in place represent both opportunities and constraints for
Characteristics feasible solutions.
The availability, cost, maintenance and service requirements,
Operational Details spare parts issues, and reliability features of new equipment
alternatives determine the technical and economic capabilities
for possible solutions.
Available incentives, the possible methods of financing, taxes,
Financial and budget constraints set or alter some costs and benefits, and
Parameters may dictate some of the project priorities. Higher discount rates
favour least first-cost solutions, and the net benefit or cost-
benefit ratio can be very sensitive to the discount rate - slight
adjustments can in many cases flip the ranking of two
alternatives.
If there are interactions between two projects such that two
Synergies projects together are more valuable than the individual projects
considered separately, then looking only at individual projects
alone will miss possibly important cost savings opportunities.
Direct costs can depend significantly on the attainment or non-
Environmental attainment area status of the location and local permitting
Considerations regulations and fees.
Quality and reliability levels in the area depend not only on
Power Quality and equipment (above) but also vegetation and climate. The realized
Reliability customer outage costs further depends on the local customer
value of service and customer demographics.
Uncertainty in data, forecasting, regulatory climate, and cost
Uncertainty estimates drive risk and strategic value, but also lead to risk
averse behaviour by planners due to fear of being wrong (e.g.
slightly overbuilding or overforecasting as a slight overcapacity
has fewer repercussions than slight under-capacity).
Are there opportunities or requirements related to public
Intangibles relations, goodwill, learning, political necessity, etc.?
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
Table 3: Objectives and Strategies for Improved Costing Methods
Objective Strategy
1. Know where costs are high. Differentiate distribution costs by
location.
2. Know when costs are high. Differentiate distribution costs by time of
day and year.
3. Formalise the evaluation process. Formally compare distribution system
improvements to the most promising DG
alternatives at the most important
locations.
4. Increase effective lead time. Consider DG alternatives as early as
possible in the planning process.
5. Ensure effective buy-in. Consider the financial interests of other
parties in calculating the net costs to
distribution utilities. Consider
mechanisms to cost-share with other
parties, and reflect these in estimates of
distribution company costs.
6. Get started with established costs. Consider the role of societal benefits a
lower priority issue.
7. Include all costs. Consider factors that are difficult to
quantify in making decisions.
The objectives in table three contain the key elements for developing a
distribution costing methodology [13] that will provide relevant and timely
temporal-locational pricing signals for prospective DG owners to decide
whether or not to invest in a particular site-specific DG project. This
information could be incorporated within current information disclosure
practices for lines network companies. Lines network companies for example,
using the information provided in table three [13], might be regulated to:
1. Differentiate marginal distribution costs by location.
This helps identify areas where DG options are most likely to be beneficial. In
doing this, utilities should consider both costs for distribution system
enhancements, and revenues by location. Revenues can vary due to
customer mix (and resulting differences in rate level and structure) and load
profile. Utilities will discover that the financial impacts of load reduction will
vary from site to site based on both costs of service and marginal revenues.
2. Differentiate marginal distribution costs by time of day and
year.
To select an appropriate DG solution, it is particularly important to understand
both when the peak loads that drive distribution improvements are occurring,
and what is causing those loads.
3. Formally compare distribution system improvements to the
most promising DG alternatives at the most important locations.
DG planning is a significant investment of time and money, and should be
pursued where it is most likely to bear fruit. If there are questions about
applicability, it is important that DG planners take the time to understand the
alternatives, and conduct screening analysis to identify potentially beneficial
DG applications. Where it is applied, distribution planning should be an
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
iterative process that identifies and compares the costs of several potential
options, including DG, to meet distribution system requirements.
4. Consider DG alternatives as early as possible in the planning
process.
Some DG alternatives have a longer lead time than typical distribution
improvements, which are often planned and installed in less than two years.
Efficiency programs, in particular, can take several years to reach maximum
benefit. To effectively implement long lead-time programs, utilities may need
to use alternative methods to their classical planning tools to “look ahead”. For
example, utilities can evaluate load trends at adjacent substations, and focus
efficiency programs in areas where there are potential capacity limits several
years out. While these long-range planning methods cannot predict the need
for capital improvements with certainty, this type of preventative action can
reduce the risk of needing “quick solution” capital improvements.
5. Consider the financial interests of other parties in calculating
the net costs to distribution utilities.
Other parties, including utility customers, energy service providers, and
generators, may gain financial benefits from DG implementation. Where
customers are willing to coinvest in efficiency and generation, this reduces the
costs of DG alternatives to the utility. Distribution companies should explore
these areas of mutual financial interest, but distribution planning should reflect
them only as they become practical options.
6. Consider the role of societal benefits a lower priority issue.
Benefits can occur to the public at large, including economic development,
less pollution, impacts on land use and visual aesthetics, etc. Many US states
have in the past created regulatory and rate mechanisms to encourage
utilities to pursue energy efficiency to achieve these goals. In some cases
multipliers or adders have been established to reflect these values in least-
cost planning. Commensurate provisions have also been made in many US
states to assure that, where utilities fund initiatives that are rendered cost
effective by these adjustments against their own economic self-interest, they
have mechanisms to recover costs and (in some states) achieve additional
profit.
7. Consider factors that are difficult to quantify.
It is neither practical nor economical to quantify everything that is important for
every proposed capital investment. Progress is likely to be faster if distribution
planners and their managers use a decision-making process that explicitly
considers both quantifiable factors and “intangibles”. The “intangibles” could
include political and public relations issues, financial risks that are not formally
modeled, environmental and broad economic benefits, and so on as
appropriate.
For most if not all utilities in New Zealand, the practices proposed in the
“Utility-Driven, Customer Response Framework” differ substantially from
existing regulatory requirements and business operating practices. There are
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
however, concrete steps that Government and utilities can take to adopt a
more practical, proactive approach to optimum DG facilitation in New Zealand.
“These initial steps consist primarily of evaluating current status and
developing a vision and roadmap for improving costing practices” [13]. This
concept is developed further in the next section, under the “Temporal-
Locational Market-Driven” legislative Framework for facilitating DG.
D. Temporal-Locational Market-Driven Framework
Complete cost transparency of temporal-locational market-driven prices
should be site specific and publicly disclosed. The greater the number of sites
listed, the greater the probability that prospective DG operators will identify
economically viable time- and location-specific DG investment opportunities.
This is necessary for sustainable DG facilitation in New Zealand.
“The key concept of de-regulation in nearly every nation is that no one
company should have a monopoly on either the production, the wholesale
sale, or the retail sale of electricity and electricity-related services” [14]. Under
this arrangement, DG-operators should be able to competitively negotiate the
supply of electricity to energy retailers or customers at temporal wholesale
prices (i.e. a Time-of-Use wholesale market price) or at a pricing-schedule
equivalent to the existing energy pricing contract between a typical energy
retailer and the DG-operator functioning as an energy consumer (minus a
reasonable administration fee of say 5-10% of the energy price). Introducing
alternative arrangements outside the wholesale market for transacting DG
energy, and matching regional distribution network-specific demand with
network-embedded DG, could help facilitate temporal wholesale pricing of
DG.
The New Zealand electricity wholesale market does not support localised or
regional trading of DG under the existing regulatory environment. Significant
steps towards rectifying this situation can be taken however, by introducing
appropriate policy mechanisms and market incentives encouraging market
participants to develop innovative, reliable, and less risky methods of meeting
the nation’ s demand for electricity (e.g. a reserve-market for dry-year
contingencies). Policies considered or planned include: demand-side bidding
and multi-settlements; demand response (participation of load management in
spot markets); opening the ancillary services market to DG (e.g. outsourcing
network capacity planning); resource aggregation and management;
increasing market liquidity; more economically efficient transmission and
distribution rate design; and, public benefits programs, including funding
mechanisms, in support of investment in long-term end-use energy efficiency
[15].
The distinction between the Temporal-Locational Market-Driven framework
proposed in this paper and the traditional central utility structure employed in
New Zealand, is exhibited in figure one below. In the left side of figure one,
the central hub generation and spoke transmission and distribution has been
the typical pattern adopted by utilities to generate and supply electric energy.
On the right side, a schematic of the possible structure of a future utility is
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
presented. The schematic indicates that central station power plants will be
integrated with distributed generation and storage devices. In certain cases,
utility owned or operated modular generation technologies can serve remote
loads that are too expensive to connect to the utility grid.
T o d a y 's T o m o r r o w 's
C e n tr a l U tility D istr ib u te d U tility ?
is tr
C e n tr a l G e n e r a tio n C e n tr a l G e n e r a tio n
W in d
R e m o te
G e n se t L oads
PV
F u e l C e ll
B a tte r y
C u s to m e r
C u sto m e r s E ff ic ie n c y
M ic r o tu r b in e
1
Can Costly Upgrades Be Prevented?
© 2 0 0 2 D i strib uted U tility A ss ocia te s
Figure 1: The Distributed Utility [16]
Locationally Based Marginal Costing (LBMC), is “a method of transmission
pricing in which the actual (technical) cost of power at every location in the
power grid is computed using some mutually agreed upon method, and the
price for power transmission between any two points in the grid is then
defined as the difference in the computed local prices” [14]. These prices are
determined from electricity transmission losses and transmission limits
(network constraints). These physical impediments to electricity trading cause
competitive prices to differ, the difference being the price of congestion [17].
As a result, if the transmission line between two locations is inadequate to
handle the desired trade between those two locations, the downstream
location will be forced to buy power from more expensive local generators.
This will raise the local price of power relative to the remote price, which is a
standard competitive result and has nothing to do with centralised
computation. This standard procedure is used by Transpower to charge
distribution networks for delivering capacity to the Grid Exit Points (GXPs)
where electricity transmission ends, and local / regional electricity distribution
begins. Locationally Based Marginal Costing is used by Orion Networks to
determine the temporal-locational value of DG capacity within its electricity
distribution region [18,19].
At the moment, Orion Networks provides a single temporal-locational value for
DG capacity contributions, alleviating annual electricity distribution constraints
impacting its GXP locational fees to Transpower (the national transmission
network operator). If the utility-driven, customer-response costing
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
methodology was adopted universally by distribution networks throughout
New Zealand, temporal-locational values for DG capacity contributions could
be calculated individually for every GXP and every feeder station as well. The
consequence of such a move would be to create a realistic picture of the net-
worth of DG capacity contributions throughout the distribution networks. Such
a move would create the “ultimate” secondary temporal-locational energy-
capacity market for facilitating DG in New Zealand.
In c r e a s in g V a lu e C r e a tio n fo r N Z M a r k e t (P r o a c tiv e )
A c c e le r a te d G r o w th & E x p a n s io n
o f D G M a rk e t
In c r e a s e d C o n tr o l
Govt & Utility Constrained DG Market
Govt & Utility Sustained DG Market
& C o n ta in m e n t o f D G M a rk e t
A B C D
C u s to m e r- L e a s t-c o s t U tility -d r iv e n , T e m p o r a l-
d r iv e n a s s e t c u s to m e r- lo c a tio n a l
u tility - m a n a g e m e n t re s p o n s e m a rk e t d r iv e n
re s p o n s e fr a m e w o rk fra m e w o rk fr a m e w o rk
fra m e w o rk
S O E ’s r e ta in m a r k e t s h a r e o f N Z ’s
g e n e r a tin g c a p a c ity
L in e s c o m p a n ie s & IP P ’s in c r e a s e m a r k e t
s h a r e o f N Z ’s g e n e r a tin g c a p a c ity
In c r e a s e d R is k M itig a tio n F o r E le c tr ic ity M a r k e t (R e a c tiv e )
Figure 2: Impact on New Zealand of Adopting Different Legislative Frameworks for
Facilitating DG
Summary
The impact these different frameworks are likely to have on the New Zealand
electricity market, are summarised in figure two. It is interesting to note that
the pace of technological change usually precedes the pace of business
innovation required to accommodate the new (technologically-enabled)
opportunities realised. Furthermore, the commercial market derived from the
prevailing regulatory / legislative environment is usually even slower to
respond to the new business requirements identified (to make the new
opportunities work). Some businesses may encounter minimal resistance to
creating new markets, simply because appropriate legislation has not been
developed yet and regulations do not exist: for example, the internet in its
early days. Other businesses however, may encounter stiff resistance to
proposed market changes, especially if entrenched market positions of market
incumbents are threatened: for example, telecommunications and electricity.
Conclusion
According to a recently released report by the US Congressional Budget
Office [20], “If the new rules and prices are well designed, the cost of
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
providing highly reliable electricity service to customers who desire it and the
total cost of serving all customers will probably fall as distributed generation
becomes more widely used.” This paper describes four progressive
frameworks for facilitating this new rule- and price-making process (see figure
two).
References
[1] Government Discussion Paper (GDP), “Facilitating Distributed Generation”,
Ministry for Economic Development, September 2003.
[2] GDP Paragraph 44.
[3] GDP Paragraph 34.
[4] The Press, “Project defended” (Perspective, page A11), October 30th
2003.
[5] GDP Paragraph 39.
[6] Refer to Pupu Springs Hydro’s submission to the Electricity Inquiry in 2000
on Energy Retailer Power Purchase Agreements, entitled: “Submission #3:
Pupu Hydro Society”.
[7] Refer to Industrial Research’s submission to the Electricity Inquiry in 2000
on DG impacts of the existing NZ Electricity Market, entitled: “Submission
#343: IRL Electrotec Group”.
[8] GDP Paragraph 43.
[9] This was the case when Christchurch City Council wanted Meridian to
supply 3% of its electricity demand from Windflow’s 500kW wind turbine on
the Banks Peninsula. Only when Christchurch City Council threatened to
switch energy retailers did Meridian Energy comply with their request.
[10] Refer to the Orion Networks website for information regarding alternative
approaches taken by lines companies for rewarding / penalizing capacity-
support from customer-driven DG (http://www.oriongroup.co.nz).
[11] GDP Paragraph 33.
[12] Refer to Industrial Research’s DG website at: http://www.irl.cri.nz/
[13] This methodology is discussed in a report of the same title found at
http://www.energyfoundation.org/documents/CostMethod.pdf
[14] Philipson, Lorrin. and Willis, H. Lee, “Understanding Electric Utilities and
De-Regulation” , Marcel Dekker, Inc., New York, 1999.
[15] Weston, F. et al., Accommodating Distributed Resources in Wholesale
Markets, The Regulatory Assistance Project, Montpelier, Vermont, September
2001.
[16] Chapel, S et al., Distributed Utility Valuation Project Monograph, EPRI
Report TR-102807, Final Report, June 2000.
[17] Stoft, S., Power System Economics: Designing Markets for Electricity,
IEEE Press, Wiley-Interscience, New Jersey, 2002.
[18] The Economics of Grid Connected Hybrid Distributed Generation, I A
Sanders, A I Gardiner, Electricity Engineers Association of NZ, Christchurch,
20-21 June 2003.
[19] Full 57-page report (of the EEA paper described in [2]) entitled: “Wind-
Diesel Hybrid Potential” may be downloaded from: http://www.irl.cri.nz/
[20] Prospects for Distributed Electricity Generation, The Congress of the
United States, Congressional Budget Office, September 2003.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
[21] Grid 2030, A National Vision for Electricity’ s Second 100 Years:
Transforming the Grid to Revolutionize Electric Power in North America,
United States Department of Energy, Office of Electric Transmission and
Distribution, July 2003.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
6.4 Capacity Metering for General Customers - Rewarding the
Demand Side Delivery of Distributed Generation Capacity
Provided by Large Numbers of Very Small Systems
(By Alister Gardiner)
(Originally included as part of a submission by Industrial
Research to the Ministry for Economic Development on:
“Facilitating Distributed Generation”)
Definitions
General customer-generator: an electricity customer whose energy
consumption is metered by a totalising kWh meter, is subjected to deemed
profiling, and who generates behind the revenue meter, primarily for own
consumption. Distribution Company: the organisation that is responsible for
power distribution in a specific region, which normally owns and operates the
electrical distribution system. Micro-DG: Distributed generation of capacity
less than 100kW per site, and generally less than 10kW.
Summary
There is strong justification for metering very small scale DG capacity
Micro-scale distributed generation (micro-DG), i.e. very small-scale distributed
generation generally connected behind (on the load side) of a revenue meter,
offers a substantial opportunity for environmentally sustainable alternatives to
the expansion of centralised supply side generation, transmission and
distribution infrastructure. At present the electricity market has no mechanism
for valuing the capacity that micro-DG can offer. Indeed, the industry is just
getting to grips with how to value and transact the energy associated with DG
connections. New Zealand currently has an excellent opportunity to lead the
world in setting up a regulatory framework to provide fair access to the
network for micro-DG. This paper shows how standard kilowatt-hour metering
technology can be used to value and reward the capacity that any micro-scale
own generation plant contributes to the network, down to the smallest size.
This metering approach is low cost and economically efficient, and if adopted
will simplify the currently propose regulations as applying to small general
customers [1].
The basic premise of this proposal is that all generators, no matter how small,
are entitled to use of the network, and that they should be rewarded for the
capacity, as well as the energy that they deliver to the network.
This proposal is the main conclusion from several years research into the
reasons for lack of uptake of very small scale distributed generation. Without
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
the introduction rules that provide for payment of capacity supplied by these
generators, an opportunity for better alternatives to supply side expansion will
be lost, and consumer choice will be curtailed.
Introduction
The market structure must allow efficient choice of delivery
Efficient and cost effective delivery of electricity services is fundamental to
New Zealanders’ economic and social well-being. The environmental impact
of providing these energy supplies is significant and of increasing concern,
and should be minimized wherever possible. It is imperative that an electricity
market regulatory framework is put in place to fully value any energy resource
that can be utilized in an environmentally sustainable way.
Timely delivery of electricity services requires an energy production
component, and a delivery infrastructure. Both the energy component and the
infrastructure capacity must be available when required by the customer. The
cost of infrastructure capacity can be many times the cost of energy.
Distributed generation (DG) that can provide both of these components should
be rewarded for both, even if the generation is connected behind a
consumer’s energy meter. For very small-scale distributed generation, new
metering is needed to measure its contribution to capacity.
Micro-Scale Distributed Generation
Research studies
IRL has been evaluating the economics of various micro-scale distributed
energy technologies for over five years. Many reports and papers predicting
technology performance and system economics have been published over
this time, notably in Energy Wise News and at the annual New Zealand
Electricity Engineers Association Conference, e.g., [4], [5], [6]. This work has
shown that based purely on energy sales, very few of these technologies are
economic, nor likely to be in the next decade. More recently, we have turned
our attention to examining and developing combinations of small-scale DG
that will improve the level of firm capacity provided in support of the
distribution system. This focus came from the realisation that the electricity
supply industry in-general currently views small-scale DG as a problem rather
than a possible solution to load growth. We have shown that if the time of use
capacity support that small-scale distributed generation technologies can
provide is fairly valued [2], some of these technologies are already viable, and
will become increasingly more economic within the next few years. This is at
present particularly relevant to rural and remote parts of the system, because
of the higher cost associated with electricity delivery to these regions. As DG
costs drop and central power costs rise, the economics will improve in wider
scale applications [4]. Overall, micro-DG could provide an economically and
environmentally attractive alternative to supply side upgrades in generation,
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
transmission and distribution infrastructure in many areas, but only if market
access regulations are in place to allow it to occur. The current proposals [1]
are inadequate in this regard.
Valuing small-scale generation capacity
Typical own-generation micro-DG technologies are photovoltaic, wind, micro-
hydro, and small fuelled generators. In this proposal, we make no distinction
between renewable and fossil resources. Our research shows that
combinations of technology such as wind-diesel hybrid generation can provide
reduced risk (i.e., more consistent capacity) and improved returns to the
owner [2]. The capacity payment received by an owner of these systems
should be valued on the basis of the statistical capacity support that they
provide during times of peak demand. To support load growth, new
centralised and medium-scale distributed generation power plants require
associated upgrades to transmission and distribution infrastructure.
Depending on the location of the load, this T&D infrastructure can cost $1,500
to $5,000 per kW (e.g. $10,000 to $50,000 per km for LV and MV lines) or
even more in remote areas, and is ultimately paid for by all electricity
customers. Since micro-DG can avoid most of the incremental transmission
and distribution infrastructure costs, measured micro-DG capacity support
should be assessed and paid for in the context of these avoided costs, and as
above, the cost passed on to electricity customers as line charges.
Potential positive impact of micro-DG
It is important to note that while many of the technologies have been available
for some decades, the level of uptake of micro-DG is practically non-existent.
This results from discouragement of private generation in pre-deregulation
days, a current absence of uniform access regulations of any sort, and poor
economics for the more widely applicable technologies (e.g. PV). However,
this should not serve as a reason to draft regulations that close off the
opportunity for these technologies to fairly compete and contribute to the
generation mix. There are approximately 1.25 million dwellings in New
Zealand. It would take an average of 5kW peak generation capacity
associated with only 10% of these households to avoid 600MW growth in
central generation and delivery infrastructure. Since micro-DG capacity will
normally be provided in conjunction with load growth, the cost/kW average is
not increased. In fact, through appropriate payment signals, load factor can be
encouraged to improve and the overall cost/kW average will reduce, i.e. the
system will be operating more efficiently. The potential for wealth creation
through an active domestic market in these small-scale energy technologies
should also not be overlooked.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
Technical Background
It is generally recognized that individual micro-DG plants of only a few
kilowatts have little impact on the distribution system, providing that basic
technical standards are complied with. There is still some concern within the
supply industry that significant levels of DG penetration in an area may cause
network problems to surface, but 20% to 40% of the connected load supplied
locally is unlikely to require special management practices. DG distributed
across a large number of sites will almost always be technically preferable to
a single injection point [7] (e.g. reduced voltage fluctuation), so this provides
ample scope for distributed micro-DG to make a substantial positive difference
to network loading.
An arbitrary maximum is often decided in treatment of very small own
generation connected behind the revenue meter. The proposed regulations [1]
recommend a maximum generator capacity of 10kW. We find no technical
reason why the DG capacity at any site should be limited to a particular low
value. It is highly unlikely that every customer on a distribution feeder will want
to connect DG, let alone up to a designated limit. Our contention is that
general customer DG connections should be allowed up to the individual
customer of the service mains capacity. This maximizes the opportunity for
network support. For a three phase 100A, 400V ICP, up to 69kVA could be
connected (3 x 23 kVA). The distribution company should have the right to
restrict new additional connections if it can be shown that the performance of
the network is at risk.
Market Background
MARIA allows energy supplied to general customers with mains of less than
100A capacity to be metered with totalising kilowatt-hour meters. This is
usually billed monthly, often by estimate every alternate month. The individual
profile of these customers is not known. A collective profile is used. These
customers represent the vast majority of electricity connections to the
distribution system, and present an ideal base for low cost connection of
embedded generation. Our view is that the energy from any distributed
generation provided by these customers, when connected behind the energy
meter should be treated in the same manner, i.e. any surplus exported energy
is simply treated as negative load. A small handling charge to manage the
energy reconciliation would be acceptable.
The capacity supplied by the generator should be treated in a similar
collective manner. There is no need to treat this collective capacity any
differently than other individual contributions delivered by larger scale DG
plants. All that is required is a metering technique to record the contributions
with adequate precision, so that the capacity value attributed to each
generator can be calculated and reconciled. A solution is described below.
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
The Metering Proposal for Small-Scale General Customer-
Generator Capacity
The approach is very simple, as indicated in fig 1. A two register kilowatt-hour
export meter is placed in series with the distributed generator connection on
the load side of the revenue meter. This is simply a standard two register
import meter with reverse stop fitted (i.e. backwards energy flow is not
recorded). It is connected in reverse, i.e. to record export kWh. The two
register meter records on-peak and off-peak kilowatt-hours of generation in
the different registers. The meter register is switched by distribution company,
at the distribution company’ s discretion. This provides a means to determine
the average kW capacity provided over any peak control period season, which
is the measure used by Orion for DG capacity payments. At least 1 charge
period (1/2hr) must be designated by the lines company for capacity payment
in each season/year, to ensure that payments will always be made to capacity
providers. An external signal for customer use must be provided. Means of
signalling this register change would be up to the distribution company, but
could include:
• Ripple control
• Radio paging
• Time clock
• Telephone modem
• Or a more specific control signal based for example on the local system
voltage level.
This capacity payment approach is in principle already implemented by Orion
Networks for larger customers. Our proposal is to standardize the application
of this principle down to any capacity level offered by a general customer-
generator. At the current Orion offer of $100/ average kW/year, this can
deliver a substantial return for a distributed generator (at present only larger
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
half hour TOU metered generators are allowed to access this payment. In
remote regions with network constraints, a case for much higher payments
can easily be made [8]. Our case study analysis for mini-scale wind-diesel
hybrid systems [2] shows that based on Orion payments, typical annual
revenue is shared 50:50 between energy production and network peak period
demand receipts.
Obligations on the Customer-Generator
This class of customer generator should not pay additional costs for this
connection since in general, there will be no incurred network upgrade costs
accruing. Indeed, if a use of system charge was made, this would
disadvantage DG against central generation, which pays no such charge.
Standard technical connection requirements appropriate for this size of
system would need to be complied with. The cost of the capacity metering and
installation should be borne by the customer-generator (preferably having the
right to own the capacity meter if desired), plus any dedicated plant necessary
to deliver the generated power to the ICP.
Obligations on the distribution company
The distribution company would be required to provide a capacity payment
schedule that, at a minimum, offered a fair payment for the on-peak kWh
exported each year, or season. The capacity payment schedule offered would
be subject to appropriate disclosure regulations, to ensure that a payment
which represents avoided T&D costs is offered, less reasonable incurred
transaction costs. Other more innovative products could be offered by the
distribution company in different regions to promote desirable load-generation
patterns. For instance, a premium could be offered for generation exhibiting a
high onpeak/ off-peak differential in regions with poor load factor to encourage
improvements. In times of national energy supply constraint, for example dry
year events, promotions could be run to encourage high total generation
levels.
The distribution company would be responsible for reading the capacity
meters and making the capacity payments to the general customer-generator.
These would be required on at least a 12 monthly basis, with terminal
payments made on request. The distribution company could appoint an agent,
who may be a retailer or other third party (such as a meter reading company)
to transact these operations. A reasonable handling charge of 5-10% for the
meter reading and data processing services would be acceptable.
Net metering
This capacity metering proposal is very pertinent to the issue of net metering
for small consumer-generators, and inherently provides for the proposed
metering of exported energy. In this discussion, we take no position for or
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
against net metering, but merely point out that the inclusion of capacity
metering will also provide total export energy.
If the existing revenue meter contains a reverse stop, the imported energy is
as recorded, and the exported energy is simply the sum of the registers on the
new capacity meter. If the existing revenue meter nets import and export, then
the total import energy is this reading plus the sum of the registers on the new
capacity meter. Export energy is the sum of the registers on the capacity
meter, as before. If it is decided under the regulations that total energy export
metering is required, the distribution company and relevant retailer would
need to enter an agreement regarding collection and sharing of this data.
Summary
This metering approach provides a simple, cost effective way to record and
reward capacity support from micro-DG.
• Statistically accurate capacity pricing signals for the customer-
generator to respond to
• Capacity needs managed by distribution companies in a similar way to
load control, but not directly controlled
• Generation equipment owned, operated and maintained by customer,
so minimum administrative overhead
• Flexible options for encouraging efficient load profiles in response to
local needs
We strongly recommend that this or a similar approach to value the capacity
supplied by micro-DG be adopted by the Electricity Commission under the
new distributed generation rules.
References
[1] Facilitating Distributed Generation – A discussion paper, Resources and
Networks Branch, MED, September 2003, ISBN 0-478 26350-3
[2] The Economics of Grid Connected Hybrid Distributed Generation, I
Sanders and A I Gardiner, 2003 Annual EEA Conference, Christchurch; and,
The Economics of Mini-Scale Embedded Wind-Diesel Generation,
(elaborating on the EEA publication)
[3] Orion Distributed Generation Information Pack, obtainable from Orion New
Zealand Limited, PO Box 13896, Christchurch, New Zealand
[4] Possible Impact of Micro-Scale Distributed Energy Technologies on
Existing Supply, A I Gardiner, I A Sanders, Industrial Research Limited, NZ
Energy Conference 2002, Wellington, NZ, 7-8 October 2002
[5] Are Microgrids the Answer for Post 2013?, A I Gardiner and I A Sanders,
Electrical Engineers Association of NZ Conference, Christchurch New
Zealand, 21-22 June 2002
[6] A Renewable Resource Assessment Atlas of New Zealand, I A Sanders
and A I Gardiner, EnergyWise News, EECA, June 2000, Issue 66, pp28-30
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
[7] Deferment of Upgrades to Weak Lines Through New Technology, R D
Brough and A I Gardiner, Electrical Engineers Association of NZ Conference,
Christchurch New Zealand, 21-22 June 2002
[8] http://www.energyfoundation.org/documents/costmethod.pdf
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Network Reliability and Firm Power Capacity Workshop: December 2005 (IRL, Wellington)
This report was prepared by:
Dr. Iain Sanders
Managing Director
Sustainable Innovative Solutions Ltd.
P.O. Box 20-452
Bishopdale
Christchurch 8030
New Zealand
Tel / Fax: +64 3 359 2151
Email: sis.limited@gmail.com
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