Network Reliability and Firm Power Capacity with Distributed Energy

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)

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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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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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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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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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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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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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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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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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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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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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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.

Ref. Issues Action Points

Proposed Participation

A1

Support long-term planning. a. Long-term needs not addressed by short-term political agendas. (C1)

• Long-term contracts for energy supply and demand required. • Pricing arrangements should deliver long-term contractual arrangements that help new investors get established and give consumers who put a premium on security, contractual certainty.

Energy Minister; Electricity Commission; MED; Commerce Commission; Energy Users; Generators; Retailers; T&D Networks.

A2

Constructive stakeholder cooperation. a. Untapped potential for sustainable development due to fragmented markets. (C2) b. Many opportunities missed or lost due to lack of coordinated planning between Government and industry stakeholders. (C3) c. Short-term micro-management drives decision-making process because of distrust between Government and industry. (C4)

• Views and opinions of energy market / industry stakeholders need to be documented and presented to the MED, Electricity Commission, Commerce Commission and other Government ministries and agencies. • Responses to Government Requests for Information (RFIs) should provide concrete, evidence-based information; and, specific proposals for making changes, taking action etc. should be given where possible. • Government needs to be informed by stakeholders about problems associated with regulations and policies affecting the operation, efficiency and effectiveness of the electricity and energy markets.

Energy Minister; Electricity Commission; MED; MfE; NZTE; Climate Change Office; Office of the Parliamentary Commissioner for the Environment; Commerce Commission; Energy Users; Generators; Retailers; T&D Networks.


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Ref. Issues Action Points


A3

Effective decision-making framework.

a. 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. (C5)

b. 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. (C7)

• Chains of command, accountability and communication need to be improved within and amongst Government structures. • A more robust, transparent and technically-qualified decision making process is necessary. • Industrial stakeholders must be engaged collectively by Government in such a way that interaction amongst different organizations is supported and enhanced to achieve better results. • Acquire timely information, and the management of that information, with appropriate smart metering technology. • Adopt Area and Time Specific Marginal Capacity [ATSMC] cost programmes.

Energy Minister; Electricity Commission; MED; Commerce Commission; Energy Users; Generators; Retailers; T&D Networks.

A4

Concentrate resources to achieve a specific outcome.

a. 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. (C6)

• Restructure R&D investment so that it supports NZ Inc., and a common long-term vision for New Zealand’s sustainable economic growth and prosperity. • Create a guiding industrial-Governmental coalition with the resources needed to achieve the vision developed. • Empower broad-based action, by getting rid of the obstacles and structures that undermine the vision created. • Encourage risk taking and innovation by visibly recognizing and rewarding the organizations that make a difference towards progressing the vision’s outcomes for New Zealand.

Energy Minister; Electricity Commission; MED; MfE; NZTE; R&D organizations; Academia; Climate Change Office; Parliamentary Commissioner for Environ.; Local govt.; Chambers of Commerce; Commerce Commission; Energy Users; Generators; Retailers; T&D Networks


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Ref.

Issues

Action Points


A5

Encourage greater diversity of supply and demand to reduce risks. a. A well-structured, diverse portfolio of distributed energy (supply- & demand-side) resources, that can balance fluctuating loads with fluctuating weather patterns, is needed for long-term investment.

• Support the development of distributed energy resource portfolio business investment tools and models. • Encourage banks and other lending institutions to provide the equivalent of revolving home loan accounts for distributed energy resource project finance. • Support collaboration between business / project investors and load / renewable energy forecasters to develop acceptable & reliable financial risk management metrics. • Ensure coordination of energy investment signals with energy and capacity pricing signals, and energy and capacity usage.

Energy minister; Banks and other lending institutions; Business investors and owners; R&D orgs.; MfE; Climate Change Office; Electricity Commission; MED; NZTE; Generators; Retailers; T&D Networks.

A6

Ensure multi-stakeholder benefits derived from new energy investments cover their costs. a. Economic and other benefits derived from investing in distributed generation and demand side management are not readily realized by the project sponsor or system operator.

• Government intervention is required to reconcile benefits derived from investing in energy supply- and demand-side products, processes and services, with the costs borne by project investors. This means energy and capacity benefits obtained by energy wholesalers, retailers, T&D networks, insurance firms etc., recompense part of the investor’s project capital and operating expenditure, as applicable, by law.

Energy Minister; Electricity Commission; MED; Project Investors; Commerce Commission; Energy Users; Generators; Retailers; T&D Networks.


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4. Workshop Summary

PRESENTER MAIN POINTS

ISSUES RAISED

SPECIFIC

NEEDS

Alan Jenkins (Electricity Networks Association) Presentation: What is Reliable Firm Power Capacity? Why Do We Need it?

• Historically, the ‘Planning Division’ definition of ‘reliability’: enough plant and fuel available to meet 7% more than normal load in a winter where lake inflows had been 85% of the mean. • Historically the ‘Electricity Division’ definition of ‘reliability’: based around maintaining frequency and voltage through a centrally coordinated generation and transmission system operated to defined engineering standards. • The new market structure has created the view: ‘the market will provide’, overlooking the need to plan ahead. Consequently, focus is on creating an environment for competition to flourish, not on delivering reliability. • In the interests of creating a flat commercial playing field, NZ has tended to have a transmission-centric system. • Transmission nodal pricing is one manifestation of possessing a transmission-centric system. • People don’t like building power stations near a local node, because even a relatively small volume of new generation there will mean that the price of power from remote competing stations plummets. The net result: no significant investment, either in plant or long-term contracts. • NZ’s deregulated electricity market is operationally-focused on generation and nodally-driven by trans-mission. • It is not clear how much customers are willing to pay for reliability, and who should pay

• Long-term contracts for energy supply required. • Pricing arrangements should give local generation as well as more remote generation options a reasonable chance of succeeding. • Pricing arrangements should keep old, back-up power stations in reserve for when things go wrong, or demand gets

• Can the industry provide the reliability NZ needs?

• Who pays for R&D? • Can CPI-X deliver an economically sustainable network infrastructure for NZ’s future energy delivery reliability requirements?


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for what within the mix of customers. • 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 longer carrying the responsibility for building power stations, and new stations were actually being built close to loads. • The Bradford reforms of 1998 brought an end to this era, heavily influenced by a belief that the networks’ involvement in generation was occurring because local monopolies were imprudently building generation capacity that the country didn’t need – leaving local consumers to carry the cost through inflated lines charges. •The Bradford Electricity Reform Act of 1998 was driven by the belief that it would ‘ensure that costs and prices in the electricity industry are subjected to sustained downward pressure”. • Since 1998: distribution and transmission prices have decreased by: 10%. • Since 1998: energy wholesale prices have increased by: 45%. • Since 1998: total energy retail prices have increased by: 18%. • As a result of the 1998 reforms: there is a ban on networks trading in energy hedges. • As a result of the 1998 reforms: there is a ban on exercising any sort of influence over a generation subsidiary, which must be managed through its own officers, with its own board. • The Electricity Commission was established to address problems of:

- security of supply; - transmission losses; - grid capacity constraints; - no liquidity or transparency in forward wholesale electricity prices; and, - limited competition emerging / occurring in generation and retail.

• If network companies were investing in generation it would help Government and the

ahead of supply. • Pricing arrangements should ensure that the parties selling electricity are selling a package that includes defined, minimum reliability levels. • Pricing arrangements should give the parties who are best equipped to put commercial pressure on transporters responsibility for paying transmission and distribution. • Pricing arrangements should incentivise consumers to


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Electricity Commission achieve their objectives. • After the 1992 crisis, electricity system operations were working around a hydro ‘minizone’ (storage availability) to decide when, and if, back-up capacity is needed. Do we need to revert to these centrally imposed security arrangements? • There are not effective contingency plans in place to keep old, back-up plant available, as a consequence of constructing the electricity market in the mid-1990s around spot nodal prices without any imposed longer term pricing arrangements such as loss of load probability payments. • Existing network-level regulatory signals are very poor at dealing with supply reliability problems. The Commerce Commission’s price control formula linking volumes distributed and allowed income deters: a. energy conservation and b. uptake of distributed generation options that take load off parts of their systems (source of revenue). • Bad signals from the regulatory regime also disincentivise spending on research and development. The CPI-X thresholds only allow R&D expenditure to come out of profits 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?

make a contribution to reliability. • Pricing arrangements should deliver long-term contractual arrangements that help new investors get established and give consumers who put a premium on security contractual certainty.


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ISSUES RAISED

SPECIFIC

NEEDS

Rodney Doyle (Commerce Commission) Presentation: Extreme Events

• For Lines Companies to comply with Part 4a of the Commerce Act defining thresholds for declaration of control of lines businesses: they must demonstrate no material deterioration in reliability • SAIDI/SAIFI thresholds screening mechanism – are used to identify breaches that may warrant further investigation. • Businesses may avoid post-breach inquiry if they demonstrate: Breach due to an extreme event. • What is an extreme event? Definition from the Assessment and Inquiry Guidelines: “Where one or a small number of rare but high impact events has a significant and material impact on a business’ reliability performance”. • Difficult to use meteorological definitions of extreme events. Extreme weather limits are location specific, open to argument, and Extreme events may not be meteorological. • Extreme events are self-defining. Key requirements for defining a measure to identify extreme events: Consistency – Applicable to all networks large or small, urban or rural. Efficiency – Clear classification of normal and extreme data. Practicality – Should facilitate metric setting. Suitability – Should use readily available data. Simplicity – Easy to understand and apply.

• Views and opinions of energy market / industry stakeholders to be expressed and presented to the Commerce Commission.

• If a subjective process is used to define an “extreme event”, why use an objective mathematical process to analyze it? • The existing process proposed for handling extreme events cannot make decisions fast enough to address the needs raised. • Priority is to encourage best practice in outage mitigation, supply restoration and network design.


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• Steps to identifying an extreme event:

1. Collect up to five years of historical outage data

2. Calculate natural log of daily SAIDI figures.

3. Calculate alpha (α) (mean of the log values).

4. Calculate beta (β) (standard deviation of the log values).

5. Formula for an extreme event day boundary: e(α + 2.5 β). • If an extreme event is identified:

� Exclude data for extreme event days from SAIDI records. � Calculate average daily SAIDI of residual (last 5 years).

� Substitute extreme event days SAIDI figures with average.

� Calculate new annual SAIDI figure.

� Test if threshold is exceeded.

� Decide on action.

• Need consistent reporting practices from lines businesses; Standardised reporting information for those in breach; Issues in reporting of “Step” restoration type interruptions; Appropriate allocation of outage cause; Evidence of extreme events to be notified to Commission a.s.a.p. to facilitate investigation and decision. • The Commerce Commission recognise the geographic diversity;

There-fore proposal aimed at improving existing practices more than providing an effective method for dealing with real-time operational requirements. Focus is on reducing problems and / or improving responsiveness to current problems. • Extreme weather events are very difficult to anticipate from historical data, weather patterns and the shear complexity of the statistical models (and hence their reliability) involved. • Conclusion:


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Distribution businesses should still identify best practice: outage mitigation, supply restoration procedures, and network design; Aim of improving overall service reliability.

industry is very nervous and wants to be heard over the Commerce Commission’s proposed thresholds regime.


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ISSUES RAISED

SPECIFIC

NEEDS

Robert Reilly (on behalf of Roy Hemmingway) (Electricity Commission) Presentation: Alternatives to Transmission

• Electricity Commission (EC) responsible primarily for:

- overseeing electricity industry and markets. - ensuring dry-year reserve. - Conducting electricity efficiency programmes; and - regulating Transpower.

• Transpower proposes Grid Upgrade Plans (GUPs) to EC. Focus: 400kV Whakamaru-Otahuhu transmission upgrade. • EC involved because:

- Load in Auckland is growing. - A solution needed to meet demand at peak times by about 2010. - Transpower requires EC approval to be able to pass costs of investment on to

its customers. - EC must decide if Transpower’s proposal is best solution. Assessment includes

application of GIT. - EC must ensure other options have been analysed, including generation and

demand-side alternatives. • Generation options considered:

- G1: Baseload co-generation (84MW co-generation at Marsden by 2010.) - G2: Baseload coal generation (320MW coal generation at Marsden by 2010 and

320MW additional coal generation at Marsden by 2016.) - G3: Baseload gas generation (385MW CCGT at either Rodney or Otahuhu by

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

• Wide range of possible options and alternatives to transmission upgrade in the Akld region have been considered. Options favoured include: building surplus capacity into existing proposed solutions to address future needs and reduce overall costs, and incorporate small intermediate investments to buy time (defer investments)


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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).


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ISSUES RAISED

SPECIFIC

NEEDS

Gareth Wilson (MED) Presentation: Facilitating Investment in Generation by Lines Companies

• Lines companies can own: Non renewable generation up to 50 MW or 20% of lines capacity. • Lines companies can own: Unlimited new renewable generation (e.g. wind). • Lines companies can own: Reserve generation contracted to Electricity Commission. • Capacity above 5MW or 2% is subject to arms length restrictions. • Lines companies also prevented from trading in electricity generally and buying and selling hedges. • Exemptions from some or all of the restrictions may be granted on a case by case basis. • Restrictions in place to minimise the opportunity and incentive for lines businesses to: inhibit competition; and/or cross-subsidise generation and retail activities. • Should arms length rules be relaxed?

- Should the capacity threshold be raised? - What rules should apply to generation connected to another line owner’s

network? • Should the legislation explicitly set out criteria for exemptions? • Should lines companies be able to trade in hedges? If so, to what level?

Submissions should provide concrete, evidence-based information; and, specific proposals for making changes, taking action etc. should be given where possible.

• Advanced metering provides value for managing existing and new energy options more effectively – who is investigating these opportunities? Where is the funding to research how new technologies can improve the operation of the electricity market? • No research has been done on whether the market structure we now have is appropriate.


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• How could legislative uncertainty be reduced? • Discussion paper to be released March 2006 for comment from relevant stakeholders.

• It is not clear 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.


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ISSUES RAISED

SPECIFIC

NEEDS

Robert Reilly (Electricity Commission) Presentation: The Electricity Commission’s Role and Distributed Generation

• The EC is responsible for: ensuring that electricity is produced and delivered to all classes of consumers in an efficient, fair, reliable, and environmentally sustainable manner; and, promoting and facilitating efficient use of electricity.

• Key outcomes:

- Investment in (distributed) generation, transmission, energy efficiency and demand-side management.

- Remove barriers to distributed generation.

- Access to lines for distributed generation.

- Arrangements for the sale of surplus small scale generation.

- Switching and reconciliation of small scale distributed generation.

• The Government proposes to introduce regulations prescribing reasonable terms and conditions on which line owners and electricity distributors must enable generators to be connected to distribution lines.

• The objective is to facilitate the use of distributed generation by ensuring that it does not face undue barriers in connecting to lines.

• The Electricity Commission will have responsibility for administering the regulations and for proposing amendments as required.

• The Electricity Act 1992 provides powers to regulate terms and conditions for the

• Electricity Commission wishes to be informed about problems associated with the model arrangements for the sale and purchase of surplus electricity.

• Small scale generation only gets value for capacity from separate agreements with distribution networks – retailers do not value capacity delivered. • The cost of installing export meters could be a barrier to DG uptake. • Separate agreements are needed with the retailer and the distributor to gain full value from operating DG.


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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.


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ISSUES RAISED

SPECIFIC

NEEDS

Duncan Head (Vector Networks Ltd.) Presentation: Mass Market Load Control Issues

• Load management is useful when aggregated – due to scale and diversity. • Demand-side is the ability for customers to effect an outcome on the electricity system / market. • Load management involves an agreement with a customer to turn off a nominated appliance or replace dependence on the network for an agreed duration. • There are a variety of historical technologies in place. Future ability and scope is growing with convergence of communications and energy infrastructures. • Demand-side participation is not a “public good”, and it depends on the consumer’s choice between price and quality. It is left to value-seekers to incentivise uptake. • Demand-side has many valuing-adding applications:

- Transmission: congestion relief, alternatives, emergency management. - Distribution: capital deferment, asset utilization. - Customer: transmission pricing, load management (under time of use pricing). - Retail/Generation: energy hedging, portfolio & risk management. - Other: energy hedging, spot market influence, compliance management,

ancillary energy market services (e.g. voltage, under frequency). • It is doubtful whether any real long-term benefit is provided by the Transmission Pricing Methodology (‘TPM’). • Controlling to TPM targets can bring forward investment in distribution network without minimizing Transmission build.

• Coordination of energy investment signals with energy usage required.

• Purchase of cheap controllable load (from customers) is a big opportunity for lines companies to increase network asset management efficiency and economic value – but load management solutions must provide value to all stakeholders in the value chain. • Issues for effective load management include: gaining benefit from the transmission pricing methodology


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• Ability to reconcile actual benefits to third parties limiting demand-side application to non-distribution users. • Alignment of basic building blocks will enable value of demand-side to be realized. • Load management needs to create value for those involved. • An integrated system is required to gain network benefits from load management. • Specific outcomes for network distribution load management are: network management, asset deferral, and satisfactory customer price-quality trade offs. • Focus on reducing numbers of customers on traditional controlled appliances through fuel substitution and personal choice. • Technology will change the current network load management paradigm. • Vector Networks is currently embarking on a significant rethink of load management. • Vector Networks is looking to review incentives for customers to participate in demand-side management, and how they participate. • Vector Networks is looking at reducing free riders, so that demand-side benefits go where they are created. • It is essential to be able to recognize value (created by demand-side participation etc.) and to be able to pass it on. • Change in technology creates opportunities to establish next generation demand-side systems and strategies, so that ripple plant’s days and historical ownership structures may be numbered.

including reconciling peak load reductions with GXP price reductions (current difficult). • An integrated system is required to gain network benefits using SCADA technology. • Vector is looking to review incentives for customers to participate in load management options. • Load management needs to create more value for those involved. • Ripple-relay control systems act like a


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‘sledge hammer’ – no longer appropriate for managing loads effectively. • Transmission pricing does not reflect system peaks.


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ISSUES RAISED

SPECIFIC

NEEDS

Brent Noriss (The Lines Company) Presentation: The Experiences of a Network Engineer in The King Country

• Technical issues associated with installing network-embedded DG include: Connection Arrangements; Protection; Over and Under-voltages; Stability; Auto Re-closing; Ferro-resonance; Metering; Islanding; Current Flows; Power factor; Under Frequency Protection; Harmonics. • Commercial issues associated with installing network-embedded DG include: Recovery of Costs including Engineering; Transpower Avoidance Calculations; Loss Factor Calculations; Power factor; Dedicated Assets; Connection Contracts. • Industry issues associated with installing network-embedded DG include: Electricity Market ability to handle complex Distributed Generation Situations; Innovative Network Solutions; and, Plant Reliability. • DG is exciting but involves a lot more engineering than most people realize. • There is significant difficulty in getting the various stakeholders to understand the issues (let alone work together to address them!) • 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.

• Market rules required to support the complexity associated with connecting distributed generation to networks in reality.

• The option of separating electricity generators and retailers in the NZ electricity market might make it harder to address the technical issues associated with installing and operating network-embedded generation.


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ISSUES RAISED

SPECIFIC

NEEDS

Matt Todd (Eastland Networks) Presentation: Maximising Value from Distributed Generation

• Eastland Networks Limited (ENL) has commercial and operational motivations for investigating DG. • ENL network characteristics include: low consumer density, low average consumer consumption, fed by a long radial transmission line with high nodal energy prices. • Capacity is a key issue with 47MW uncontrolled and 39MW+ controlled. There is a single line, double circuit 110kV line, running through rugged erosion prone back-country. • The transmission assets are becoming n-1 constrained. • 38MW per circuit during the summer. • Peak consumption could grow to 80MW by 2011. • Price is a key issue affecting the network: large customers have been paying 4 to 7 c/kWh, new contracts (3 years) are being offered at 10 c/kWh. • For forestry processing energy is a top 3 input cost. • Investors in the region planning new developments need certainty around energy: price, supply (capacity) and contract terms (of supply / price). • Typical problem / challenge involves: investing in a forestry processing plant with a 25 year $100m investment to make, where energy is one of its top 3 input costs, and energy has risen 30% over the last 3 years, with a maximum forward (hedge) term of 3 to 5 years.

• A well-structured, diverse portfolio of distributed generation required to make it (DG) work.

• Transpower’s plans to upgrade existing circuits is limited considering forestry trends and the growth in regional processing and log exports. • ENL needs non-transmission solutions that will address energy delivery prices and capacity constraints. • The current electricity regulatory environment does not provide incentives for


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• Investors need forward certainty to invest. • Possible solutions include: upgrading the transmission line and adding a third circuit and a new GXP, but increased transmission capacity does not address the price. • Non-transmission solutions can address both the capacity and the price: e.g.

- Increased demand side management and energy efficiency measures. - Installation of Distributed Generation. - Distributed Generation is seen as a portfolio of relatively small scale generation

(sub 50MW) that provides surety of supply through diversity. - DG can address the capacity issue. - DG can address the price issue. - DG can help facilitate greater investor confidence.

• Demand side management provides better use of controllable load, and load shifting from on-peak to off-peak. • It is not possible to recover lost revenue from greater efficiency due to demand side 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

lines companies to get involved with energy efficiency and demand side management. • Forest residue is a potential source of energy, capable of deferring lines upgrades, but needs a large heat load to justify financially.


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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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- 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.


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ISSUES RAISED

SPECIFIC

NEEDS

Todd Mead (MainPower) Presentation: Renewable Energy in North Canterbury and Kaikoura

• MainPower’s interest in DG is purely community-focus-ed. They are owned by their customers, and profits returned are distributed as rebates on the power bills. • MainPower’s vision is to be a leading electricity and energy services business, committed to customer value and to the region’s prosperity. • MainPower wants to proactively respond to the energy issues facing their region. • No electricity is generated in the region, and $1 million leaves the region each week to pay for supply from generation elsewhere. • MainPower can use local wind, water and solar resources to generate energy. • Hydro power is a perfect complement to wind, and MainPower is currently investigating small scale, minimal impact projects. • MainPower has a number of pilot projects underway for micro-generation for homes and businesses, and is currently installing solar power and energy-conserving shading. • Using local resources to generate electricity will bring real benefits to the North Canterbury and Kaikoura communities, including:

- a secure and reliable supply of electricity - regional economic prosperity - a better lines business (financial and operational management)

• Significant benefits to the country as a whole include:

- a more diverse network and energy independence

• MainPower aims to be a leading energy services provider for the region which has a very high growth rate, no current generation, and a wealth transfer of over $1m per week out of the region. • Community support is vital to support existing and new alternative energy supply initiatives. Most support comes from local companies motivated by community ownership and


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- environmental gains from saved emissions • Next steps for MainPower include: wind monitoring, hydro feasibility studies, and solar energy projects. Community support is considered vital to success.

sharing of benefits.


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ISSUES RAISED

SPECIFIC

NEEDS

Iain Sanders (Sustainable Innovative Solutions) Presentation: Energy & Capacity Valuation for Three Different Networks

• 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. • There are several benefits from implementing better policies for managing electricity assets:

- Improved stewardship and accountability - Improved communication and relationships with service users - Improved risk management - Improved financial efficiency

• Improved stewardship and accountability is achieved by:

1. Demonstrating to owners, customers and stakeholders that services are being delivered effectively and efficiently.

2. Providing the basis for evaluating and balancing service / price / quality trade-

• Economic benefits from DG are greatest when lines companies are involved. In fact, financial incentives from distribution networks for delivering DG capacity can tip the balance so that DG is commercially attractive if the technical and regulatory issues can be managed effectively. Key network benefits include: lines upgrade deferral, T&D peak load reduction, and


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offs. 3. Improving accountability for use of resources through published performance

and financial measures. 4. Providing the ability to benchmark results against similar organizations

• Improved communication and relationships with service users is achieved by:

1. Improving understanding of service requirements and options. 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.

• Improved risk management is achieved by:

1. Assessing probability and 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.

• Improved financial efficiency is achieved by:

1. Improved decision-making based on costs and benefits of alternatives. 2. Justification of all costs of owning / operating assets over the lifecycle of the

assets.

standalone system replacement of stranded / underutilized network assets. • Main conclusion drawn from IRL research into economic viability of small-scale network-embedded generation: full economic benefit will only be achieved if firm capacity from network alternatives can be guaranteed. This is a major technical issue for research to address: e.g. storage alternatives, fuel dispatch strategies, control systems for DSM, energy efficiency etc.


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ISSUES RAISED

SPECIFIC

NEEDS

Alister Gardiner (Industrial Research) Presentation: Network Reliability and Distributed Energy – Technical Issues

• 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 efficiency; fuel / source switching; managing the local site demand, and/or export to the distribution network. • Other network-embedded generation issues include: power quality, safety, stability, uncertain avail-ability, large numbers of small generators difficult to control, may worsen the load factor, reduce grid energy delivered - worsening supply economics. • Micro-scale distributed energy represents a vast untapped mass market of 1.7 million dwellings in NZ, plus a large number of small commercial users. • Micro-scale systems can be used: to supply residential and commercial general 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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• 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.


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5. Supplementary Feedback from Participants Participants FURTHER POINTS RAISED

Brian Tolley Brian Tolley Corporation Limited

• 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 can be achieved by improving consumer load factors coupled with improving network component and operational performance. • 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) Alister Gardiner Industrial Research Iain Sanders S.I.S. Limited

• 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 proposed by the Retail Market Advisory Group (RMAG) of the Electricity Commission, cause unnecessary costs, 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 Distributed Generation”) and other organizations provide the necessary tools. (See Appendix 6.3 and 6.4).


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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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6.2 List of Attendees

First Name

Surname

Position

Organisation

Alan Jenkins Chief Executive Electricity Network Association

Alister Gardiner H&DE Platform Manager

Industrial Research

Ben McQueen Project Manager Industrial Research Brendon Quinn Network Manager Electricity

Ashburton Brent Norriss Engineering

Manager The Lines 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

Manager Contact Energy

Chris Freear CEO NZ Windfarms Ltd Dene Biddlecomb Chief Executive Horizon Energy

Distribution Ltd Dennis Jones Orion New Zealand

Ltd Don Lewell Engineering

Manager Horizon Energy Distribution Ltd

Doug Clover Environmental Investigator

Parliamentary Commissioner for the Environment

Duncan Head Divisional Manager, Business Development

Vector Networks

Erick Coenen Technical Support Manager

Genesis Energy

Gareth Wilson Manager of the Electricity Group

Ministry of Economic Development

Gavin Bonnett Distributed Generation

Orion New Zealand Ltd

Gerry Te Kapa Coates Managing Director Wise Analysis Ltd (wants info sent to him)

Glen Thomson Manager Grid Economics

Transpower Ltd

Greg Skelton Alpine Energy Iain Sanders CEO Sustainable

Innovative Solutions


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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

Lead Analyst Transpower Ltd

Mike Staines Industrial Research Molly Melhuish Murray Milsom Senior Project

Engineer Rockgas Ltd

Nalin Pahalawatha Team Leader Grid Planning

Transpower Ltd

Paolo Ryan Commerce Commission

Ralph Sims Dir, Energy Centre Massey University Robert Reilly Senior Advisor,

Retail Electricity Commission

Rodney Doyle Chief Advisor, Network Performance Group

Commerce Commission

Roger Paterson PowerNet Ltd Stephen Ward Strategic Energy

Advisor East Harbour Services Ltd

Todd Mead Generation Development Manager

MainPower

Tony Price Acting CEO Industrial Research Tristan Wallbank Suzlon Energy


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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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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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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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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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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 A. Improved stewardship and accountability by:

1. Demonstrating to owners, customers and stakeholders that services are 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.

B. Improved communication and relationships with service users by:

1. Improving understanding of service requirements and options. 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.

C. Improved risk management by:

1. Assessing probability and 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.

D. Improved financial efficiency by:

1. Improved decision-making based on costs and benefits of alternatives. 2. Justification of all costs of owning / operating assets over the lifecycle of the assets.


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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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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

Location

Many drivers of cost can be characterised broadly by distinctions such as Remote vs. Urban, Constrained vs. Unconstrained, and Mild vs. Extreme Climate.

Load Growth

The magnitude of the growth relative to capacity sets both the 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.

Load Shape

Distribution project alternatives that have time varying load 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.

Equipment Characteristics

The vintage, performance, and specifications of the equipment already in place represent both opportunities and constraints for feasible solutions.

Operational Details

The availability, cost, maintenance and service requirements, spare parts issues, and reliability features of new equipment alternatives determine the technical and economic capabilities for possible solutions.

Financial Parameters

Available incentives, the possible methods of financing, taxes, and budget constraints set or alter some costs and benefits, and 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.

Synergies

If there are interactions between two projects such that two 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.

Environmental Considerations

Direct costs can depend significantly on the attainment or non-attainment area status of the location and local permitting regulations and fees.

Power Quality and Reliability

Quality and reliability levels in the area depend not only on equipment (above) but also vegetation and climate. The realized customer outage costs further depends on the local customer value of service and customer demographics.

Uncertainty

Uncertainty in data, forecasting, regulatory climate, and cost 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).

Intangibles

Are there opportunities or requirements related to public relations, goodwill, learning, political necessity, etc.?


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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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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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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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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. 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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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.

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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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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[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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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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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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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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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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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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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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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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[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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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: [email protected]