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Leveraging Network Utility Asset Management Practices for Regulatory Purposes

Appendices

November 2009

Disclaimer:

The views expressed in this report are those of KEMA, Inc., and do not necessarily represent

he views of, and should not be attributed to, the Ontario Energy Board,

any individual Board Member, or OEB staff.

Table of Contents

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Table of Contents

Synopsis of International Markets Studied ........................................................................................1 1. Appendix A: Australia.............................................................................................................. 1-1

1.1 Characteristics of Utilities Affected .......................................................................... 1-2 1.1.1 Number of Companies .............................................................................. 1-2 1.1.2 Geographic Areas Served ......................................................................... 1-3 1.1.3 Key Technical and Financial Statistics per Utility.................................... 1-8 1.1.4 Ownership Structures.............................................................................. 1-11

1.2 Assessment of Utility Investment Plans.................................................................. 1-13 1.3 Regulatory Information Requirements.................................................................... 1-17 1.4 Explicit Asset Management Requirements ............................................................. 1-19 1.5 Relevant Regulatory Instruments ............................................................................ 1-21

1.5.1 Laws and Regulations ............................................................................. 1-21 1.5.2 Codes, Rules, Filing Guidelines/Requirements ...................................... 1-23 1.5.3 Regulatory Standards, Procedures or Guidelines.................................... 1-29

1.6 Regulatory Guidance to Utility Companies ............................................................ 1-31 1.6.1 Guidelines for the Preparation of Asset Management Plans................... 1-31 1.6.2 Investment Plan Requirements for Regulatory Submissions by Utilities 1-32

1.7 Lessons Learned and Future Areas of Focus........................................................... 1-42 2. Appendix B: Germany.............................................................................................................. 2-1

2.1 Characteristics of Utilities Affected .......................................................................... 2-2 2.1.1 Number of Companies .............................................................................. 2-3 2.1.2 Geographic Areas Served ......................................................................... 2-5 2.1.3 Key Technical Statistics for German Network Utilities ........................... 2-8 2.1.4 Ownership Structures.............................................................................. 2-13

2.2 Assessment of Utility Investment Plans.................................................................. 2-14 2.2.1 General Regulatory Process .................................................................... 2-16 2.2.2 Investment Budgets for Transmission and Distribution.......................... 2-18 2.2.3 Asset Replacement Expenditure (REPEX) ............................................. 2-22 2.2.4 Quantity Adjustment Term (EFt) for Distribution Electricity and Gas... 2-23 2.2.5 Investment Supplement for Distribution Gas and Electricity ................. 2-25

2.3 Regulatory Information Requirements.................................................................... 2-26 2.3.1 Formal Data Collection Requirements – Price Control Reviews............ 2-26

2.4 Explicit Asset Management Requirements ............................................................. 2-29 2.5 Relevant Regulatory Instruments ............................................................................ 2-31



2.7 Lessons Learned and Future Areas of Focus........................................................... 2-36 3. Appendix C: Great Britain....................................................................................................... 3-1

3.1 Characteristics of Utilities Affected .......................................................................... 3-2 3.1.1 Number of Companies .............................................................................. 3-2 3.1.2 Geographic Areas Served ......................................................................... 3-3 3.1.3 Key Technical and Financial Statistics per Utility.................................... 3-7 3.1.4 Ownership Structures.............................................................................. 3-17

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3.2 Assessment of Utility Investment Plans.................................................................. 3-20 3.2.1 Overview of Ofgem’s Approach to Assessment of Utility Investment Plans

3-21 3.2.2 Detail of Ofgem’s Approach to Assessment of Utility Investment Plans3-24

3.3 Regulatory Information Requirements.................................................................... 3-33 3.3.1 Formal Requirements – Price Control Reviews...................................... 3-33 3.3.2 Formal Requirements – Annual Regulatory Reporting .......................... 3-35 3.3.3 Other Information Gathering .................................................................. 3-37

3.4 Explicit Asset Management Requirements ............................................................. 3-37 3.4.1 Adoption of PAS 55 Aligned Asset Management Practices ................... 3-38 3.4.2 Adoption of Explicit Output Measures ................................................... 3-38

3.5 Relevant Regulatory Instruments ............................................................................ 3-41 3.5.1 Laws and Regulations ............................................................................. 3-41 3.5.2 Codes, Rules, Filing Guidelines/Requirements ...................................... 3-42 3.5.3 Regulatory Standards, Procedures or Guidelines.................................... 3-42


3.7 Lessons Learned and Future Areas of Focus........................................................... 3-49 4. Appendix D: New Zealand ....................................................................................................... 4-1

4.1 Characteristics of Utilities Affected .......................................................................... 4-1 4.1.1 Number of Companies .............................................................................. 4-1 4.1.2 Geographic Areas Served ......................................................................... 4-3 4.1.3 Key Technical and Financial Statistics ..................................................... 4-6 4.1.4 Ownership Structures................................................................................ 4-8

4.2 Assessment of Utility Investment Plans.................................................................. 4-10 4.2.1 Overview of the Process ......................................................................... 4-10 4.2.2 Current Assessment Process ................................................................... 4-12 4.2.3 Current Assessment Process ................................................................... 4-23

4.3 Regulatory Information Requirements.................................................................... 4-29 4.4 Explicit Asset Management Requirements ............................................................. 4-32 4.5 Relevant Regulatory Instruments ............................................................................ 4-34

4.5.1 Laws and Regulations ............................................................................. 4-34 4.5.2 Relevant Legislation ............................................................................... 4-36 4.5.3 Codes, Rules, Filing Guidelines/Requirements ...................................... 4-38 4.5.4 Regulatory Standards, Procedures or Guidelines.................................... 4-40


4.7 Summary and Lessons Learned............................................................................... 4-46 5. Appendix E: United States ....................................................................................................... 5-1

5.1 Characteristics of Utilities Affected .......................................................................... 5-3 5.1.1 Number of Companies .............................................................................. 5-6 5.1.2 Geographic Areas Served ......................................................................... 5-8

5.2 Assessment of Utility Investment Plans.................................................................. 5-10 5.2.1 Overview of the Process ......................................................................... 5-10

5.3 Regulatory Information Requirements.................................................................... 5-13 5.4 Explicit Asset Management Requirements ............................................................. 5-15 5.5 Relevant Regulatory Instruments ............................................................................ 5-15

5.5.1 Laws and Regulations ............................................................................. 5-15 5.5.2 Codes, Rules, Fling Guidelines/Requirements ....................................... 5-16

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5.5.3 Regulatory Standards, Procedures or Guidelines.................................... 5-17 5.6 Regulatory Guidance to Utility Companies ............................................................ 5-18

5.6.1 Guidelines for the Preparation of Asset Management Plans................... 5-18 5.6.2 Investment Plan Requirements for Regulatory Submissions by Utilities 5-18

5.7 Lessons Learned and Future Areas of Focus........................................................... 5-20 6. Appendix F: British Columbia................................................................................................. 6-1

6.1 Characteristics of Utilities Affected .......................................................................... 6-2 6.1.1 Number of Companies .............................................................................. 6-5 6.1.2 Geographic Areas Served ......................................................................... 6-6

6.2 Assessment of Utility Investment Plans.................................................................... 6-9 6.3 Regulatory Information Requirements.................................................................... 6-14 6.4 Explicit Asset Management Requirements ............................................................. 6-16 6.5 Relevant Regulatory Instruments ............................................................................ 6-17



6.7 Lessons Learned and Future Areas of Focus........................................................... 6-26

List of Figures Figure 1: Transmission Networks in the AER Region.........................................................................1-4 Figure 2: Electricity Distribution Network Operators in the AER Region ..........................................1-5 Figure 3: Energy Infrastructure in Western Australia..........................................................................1-6 Figure 4: Major Gas Transmission Pipelines in Australia ...................................................................1-7 Figure 5: Gas Distribution Network in Australia.................................................................................1-8 Figure 6: Current Forms of Incentive Regulation for Distribution Companies .................................1-25 Figure 7: Submission Guidance for Forecast Commentary on Capital Expenditure .........................1-33 Figure 8: Submission Guidelines for Forecast Capex by Asset Class ...............................................1-33 Figure 9: Submission Guidelines for Forecast Capex by Asset Category .........................................1-34 Figure 10: Capex Template for Annual Reporting ............................................................................1-37 Figure 11: Template for Asset Ageing Schedule for Distributors .....................................................1-38 Figure 12: Pro Forma for Forecast Capital Expenditure by Asset Class ...........................................1-40 Figure 13: Pro Forma for Forecast Capital Expenditure by Reason ..................................................1-41 Figure 14: Market Shares in the German Gas Market .........................................................................2-2 Figure 15: German Gas Market Structure............................................................................................2-4 Figure 16: Power Transmission Areas Served (Electricity).................................................................2-5 Figure 17: Distribution Network..........................................................................................................2-6 Figure 18: Gas Market Structure by a) market areas; b) T&D system operators.................................2-7 Figure 19: Gas Pipelines in Germany ..................................................................................................2-8 Figure 20: Overview of Transmission Network (Electricity) ..............................................................2-9 Figure 21: Ownership Structure (Distribution for Electricity and Gas).............................................2-14 Figure 22: Time Schedule for Data Collection for Regulatory Purposes ..........................................2-26 Figure 23: GB Distribution Network Owner (DNO) Geographic Areas and Ownership ....................3-4 Figure 24: GB Transmission Network .................................................................................................3-5 Figure 25: GB Gas Transmission Network..........................................................................................3-6 Figure 26: GB Gas Distribution Networks Geographic Areas and Ownership ...................................3-7 Figure 27: Headline Statistics for the 3 GB Transmission Owner (TO) Networks ...........................3-12 Figure 28: Outturn Daily GB Gas Demand and Relation to Cold/Warm Weather Demands............3-17

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Figure 29: GB Network Utility Price Control Review Process Example – GB DPCR5 Process ......3-28 Figure 30: Levels of Bilateral Meetings/Workshops .........................................................................3-33 Figure 31: Proposed Output Measures put forward by GB Network Utilities...................................3-39 Figure 32: Ofgem’s Indicated Examples of Potential Output Measures for GB DNOs ....................3-41 Figure 33: Overview of the Nature of Regulatory Settlements..........................................................3-44 Figure 34: Summary of DPCR5 BPQ Tables Issued by Ofgem for Completion by all GB DNOs ...3-46 Figure 35: DPCR5 BPQ Table NL2 – Total Network Costs (Source: Ofgem) .................................3-47 Figure 36: DPCR5 BPQ Table NL3 – Forecast Volume of Condition Based Asset Replacement ...3-48 Figure 37: Electricity Distribution Businesses in New Zealand ..........................................................4-2 Figure 38: Map of the New Zealand National Grid .............................................................................4-4 Figure 39: New Zealand Electricity Distribution Businesses ..............................................................4-5 Figure 40: Gas Pipelines Companies in New Zealand.........................................................................4-6 Figure 41: Actions taken after a Threshold Breach ...........................................................................4-19 Figure 42: Planned Timetable for the Reset Process .........................................................................4-20 Figure 43: Role of Input Methodologies in Amended Commerce Act ..............................................4-25 Figure 44: Assessment Management Form for Distributors ..............................................................4-43 Figure 45: FS2 Regulatory Asset and Financing Statement ..............................................................4-44 Figure 46: MP2 Performance Measures.............................................................................................4-45 List of Tables Table 1: Transmission and Distribution Companies in Australia ........................................................1-2 Table 2: Transmission Pipeline and Distribution Companies..............................................................1-3 Table 3: Major Transmission Companies in Australia ........................................................................1-9 Table 4: Major Distribution Companies in Australia...........................................................................1-9 Table 5: Major Regulated Gas Transmission Companies in Australia ..............................................1-10 Table 6: Major Gas Distribution Companies in Australia .................................................................1-11 Table 7: Ownership of Electricity Transmission Companies ............................................................1-12 Table 9: Ownership of Electricity Distribution Networks .................................................................1-12 Table 10: Ownership of Regulated Gas Transmission Networks ......................................................1-13 Table 11: Ownership of Regulated Gas Distribution Networks ........................................................1-13 Table 12: Latest Dates for Transmission and Distribution Determinations by AER.........................1-26 Table 13: Timetable for Access Arrangement (Source: Draft Access Arrangement Guideline) .......1-27 Table 14: Timetable for Electricity Access Arrangements in Western Australia ..............................1-28 Table 15: Timetable for Gas Access Arrangements in Western Australia ........................................1-29 Table 16: Number of Electricity Transmission & Distribution System Operators in Germany ..........2-3 Table 17: Number of Gas Transmission & Distribution System Operators in Germany.....................2-5 Table 18: Network Length (Germany).................................................................................................2-9 Table 19: Key Figures of German Power Transmission Companies .................................................2-10 Table 20: Key Figures of German Gas Transmission & Distribution Companies.............................2-11 Table 21: Number of Customers per Utility in Germany (Electricity) ..............................................2-13 Table 22: Number of Customers per Utility in Germany (Gas).........................................................2-13 Table 23 Criteria that Need to be Met for Quality Adjustment Criteria ............................................2-24 Table 24: Excerpt from the Data Collection Template (Betriebsabrechnungsbogen) .......................2-27 Table 25: Worksheet of Data Required by German Regulator ..........................................................2-36 Table 26: GB Electricity Networks – Headline Statistics....................................................................3-8 Table 27: Customer Numbers and Units Distributed of the GB DNOs by Voltage Level ..................3-8 Table 28: Key Technical Characteristics of the GB DNOs .................................................................3-9 Table 29: Network Circuit Assets of the GB DNOs by Voltage Level .............................................3-10 Table 30: Capex, Opex and Derived Revenue Allowance for GB DNOs for 2005/06 – 2009/10.....3-10 Table 31: Regulatory Asset Values of the GB DNOs........................................................................3-11

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Table 32: Key Technical Characteristics of the GB Electricity Transmission Networks ..................3-12 Table 33: Capex, Opex and Derived Revenue Allowance for GB TOs for 2007/08 – 2011/12........3-13 Table 34: Regulatory Asset Values of the GB TOs ...........................................................................3-13 Table 35: Key Facts and Figures for National Grid Gas Networks ...................................................3-14 Table 36: Key Facts and Figures for Northern Gas Networks...........................................................3-15 Table 37: Key Facts and Figures for Scotia Gas Networks ...............................................................3-15 Table 38: Key Facts and Figures for Wales & West Utilities............................................................3-15 Table 39: Capex, Opex and Derived Revenue Allowance for GB Gas DNOs 2008/09–12/13 .........3-16 Table 40: Capex, Opex and Derived Revenue Allowance for GB Gas TO 2007/08 –11/12.............3-17 Table 41: GB Network Utility Ownership.........................................................................................3-18 Table 42: Electricity Distribution Statistics .........................................................................................4-7 Table 43 Gas Transmission Statistics .................................................................................................4-8 Table 44 Gas Distribution Statistics.....................................................................................................4-8 Table 45: Ownership of Electricity Distribution Companies...............................................................4-9 Table 46: Ownership of Gas Distribution Companies .......................................................................4-10 Table 47: X Factors for Network Businesses.....................................................................................4-18 Table 48: Number of Threshold Breaches .........................................................................................4-20 Table 49: Process for Developing Input Methodologies....................................................................4-26 Table 50: Gas Pipelines Subject to Regulation..................................................................................4-29

Synopsis of International Markets Studied

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Synopsis of International Markets Studied This appendices document is a stand-alone document which supports the KEMA report entitled “Leveraging Network Utility Asset Management Practices for Regulatory Purpose” produced by KEMA for the Ontario Energy Board (OEB) staff. It provides extensive material reviewing international regulatory practices for markets in Australia, Germany, Great Britain, New Zealand, the US and Canada, encompassing:

1) Characteristics of utilities affected;

2) Assessment of utility investment plans;

3) Regulatory information requirements;

4) Explicit asset management requirements;

5) Relevant regulatory instruments;

6) Regulatory guidance to utility companies; and

7) Lessons learned and future areas of focus.

To aid the reader in choosing which markets to review in more depth as support or otherwise to reading the main report, we provide a short synopsis of the key features of each market and their adopted regulatory approaches to review of network utility investment plans and asset management practices below.

Australia

The examination of the use of asset management principles by Australian economic regulators has looked at the requirements from both the Australian Energy Regulator (AER), which covers the majority of the country, and the Economic Regulation Authority, which covers Western Australia. The AER was only created on 1 July 2005 and while they have made a number of transmission determinations, no electricity distribution determinations have been finalized or gas determinations yet undertaken with many utilities still currently subject to state regulation. However, the AER’s processes for regulation are well specified in national rules and guideline documents and show a consistent approach to regulation across utilities where appropriate and allowed under legislation.

Most of the regulated utilities in Australia are of a significant size, which justifies a rigorous regulatory process to set revenues. This typically has a process that includes pre consultation, submission by the utilities open to public submissions, draft decisions, and final decision. The process normally last around a year after pre-consultation and a price control is usually established for a 5 year period. Third party review of investment plans is a key part of this process in allowing the regulator to make a draft and final decision and these expert reports will be published and normally include an examination of asset management plans.


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In Australia, there is no particular asset management standard that has been adopted and it seems unlikely that there will be one in the near future. While some utilities have adopted the PAS 55 standard, others believe it to be inappropriate. The AER does not provide any particular standard that needs to be followed. Some companies also need to comply with jurisdictional policies for asset management, which may govern the policies they adopt. The ERA also do not specify a particular standard but do make reference to the International Infrastructure Management Manual – Version 3.0 as providing a best practice framework for the management of infrastructure assets for small electricity and gas licenses.

Germany

Germany has a small number of large electricity and gas network utilities and a very large number of small, typically municipal utilities. Network utility regulation is driven by legislation and applies a largely formulaic approach to setting revenue allowances. The exact form of regulation varies dependent on the size of the network utility; with the larger companies subject to more rigorous assessment. However, energy regulation in Germany does not yet place a high emphasis on review of asset management and there are no explicit requirements for or assessments of network utility asset management practices.

Great Britain

Great Britain consists of a limited number of large network utilities. A number of these own a mixture of transmission and distribution networks and/or electricity and gas networks – some also own generation and/or supply businesses; though these are ring-fenced from network interests. Network utility regulation is highly evolved in Great Britain having been first adopted in 1990 and encompasses a wide range of regulatory tools and methodologies. Regulatory review of network utilities’ investment plans is extensive and detailed with well developed information requirements and submission assessments and annual reporting processes.

In recent years, due to the context of aging infrastructure and rapidly escalating non-load related (principally asset replacement) expenditures by network utilities, the Great Britain regulator Ofgem has increasingly and intensively reviewed network utility asset management practices to seek to determine the efficiency, sustainability and thus, validity of network utility investment plans. Furthermore, they have implicitly required network utilities to adopt PAS 55 compliant asset management practices and are the first to seek to implement output measures based regulation of network utility investment plans and underlying asset management within the ongoing Great Britain Distribution Control Price Review 5.

Ofgem is commonly regarded in international regulatory circles as applying leading regulatory practices in relation to review of network utility asset management and derived network investment plans.


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New Zealand

New Zealand has an unusually high number of electricity distribution companies (29) for a relatively small country. All the other gas and electricity network businesses are much more concentrated with between one and four main businesses in each area. The regulatory approach is also different from that observed in the comparator countries with a process of targeted price controls, where companies are not automatically subject to controls, but become potentially subject to controls if they breach one or more performance thresholds.

New legislation was passed in 2008 that recognized the diverse set of distribution utilities in New Zealand in terms of size and ownership structure. Small consumer owned distribution businesses will only be subject to information disclosure, while the larger/shareholder owned companies face default/customized price-quality paths in addition to information disclosure. The current information disclosure requirements are quite extensive with the annual disclosures expected to be the primary data used in setting future default price-quality paths. These disclosures also require all distribution companies to produce annual asset management plans with clear guidelines as to the information that is expected to be included.

While asset management plans are clearly needed for all businesses (either explicitly or as part of an investment plan review) there are no specific asset management standards or processes that are enforced by the Commerce Commission (which regulates all the network businesses) or the Electricity Commission (which jointly regulates the electricity transmission business).

United States (US)

The US market is regulated by a mix of federal, state, and local entities depending upon jurisdictions and the utility services provided. The Federal Energy Regulatory Commission (FERC) regulates the interstate transmission of natural gas, natural gas pipelines, natural gas storage, liquefied natural gas facility construction, all electricity wholesale generation, wholesale power and wholesale transmission services that are not part of a unified vertical utility (with the exception of Texas).

State Public Utility Commissions have jurisdiction over intrastate natural gas pipelines and their associated local distribution systems and regulate vertically integrated electric utilities’ generation, transmission, and distribution. In states where electricity market restructuring has unbundled transmission from distribution, the state Commissions retain jurisdiction over the utility distribution function. In addition, some states regulate certain aspects of municipal utilities and/or co-ops, including rates. Municipal Utilities (Munis) are public power utilities that typically operate as natural monopolies for local electricity and/or natural gas distribution to end-users in their municipality. Munis are governed by elected public officials, such as city councils or by boards of appointed or elected individuals, and are non-profit organizations that typically operate as a division of the local city government and are not generally regulated by the state. Electric Cooperatives are private, independent electric utilities owned by the members they serve and run by a democratically elected board.


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The basic standard of rate regulation in the US is the revenue requirements standard, which provides revenues that allow a utility to cover operating costs and earn a reasonable rate of return on property devoted to the business. The determination of required revenue involves the determination of three major items: 1) allowable operating costs; 2) net value of the investment in property; and 3) a fair rate of return. To determine a rate of return on rate base that is appropriate for the overall cost of capital, the Commission first identifies the components of the utilities capital structure. Capital programs must typically be documented in the filing package to be included in the capital structure. This documentation must include a description of the program, costs and benefits. While individual capital programs (not overall asset management plans) are scrutinized for prudence during the rate setting process, no explicit asset management requirements are involved in the analysis.

Canada (British Columbia)

The British Columbia (BC) electricity transmission and distribution network is dominated by a commercially-owned Crown operation and its separate transmission operator. This company serves approximately 95% of the province’s population and 1.7 million customers. The remaining 5% of the population is served by five investor-owned utilities and six municipal utilities. The transmission operator was incorporated in May 2003 as a new Crown company in order to maintain, operate and plan transmission assets under the terms of an Asset Management and Maintenance Agreement.

The BC natural gas industry is characterized by transmission and distribution monopolies with a competitive supply market. The BC natural gas industry is not vertically integrated and transmission and distribution services may or may not be provided by the same company. BC exports approximately half of its natural gas production. The British Columbia Utilities Commission (BCUC) regulates the transmission and distribution of natural gas, but does not regulate the competitive market for natural gas.

The BCUC reviews and approves rates, return on equity, operation and maintenance expenditures, and capital investments of electricity and natural gas utilities. The BCUC has traditionally used a cost of service analysis to regulate utility rates and investment plans; however, they are continuing to introduce incentive regulation in the form of performance based rates.

Appendix A: Australia

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1. Appendix A: Australia Background and Responsible Regulators

The Australian Energy Regulator (AER) is responsible for electricity transmission networks and interconnectors in the National Electricity Market (NEM). This covers the states of Queensland, New South Wales, Victoria, Tasmania and South Australia and the Australian Capital Territory (ACT). The AER regulates transmission networks based on the framework established in the National Electricity Rules (NER). This approach requires determination of a revenue cap for each transmission network, which sets the maximum allowable revenue a network can earn during the regulatory period (which is specified in the rules as at least 5 years) and will require an investment allowance (capital expense) to be agreed at the start of the regulatory process. This process also requires a regulatory test assessment for individual projects to check for economic efficiency.

The Economic Regulation Authority (ERA) is responsible for transmission regulation in Western Australia; there is no transmission network in the Northern Territory. Western Power’s South West Interconnected Network is the only regulated electricity network within the state and is regulated under the Electricity Network Access Code. The Code sets the first regulatory period at only 3 years (which is shorter than the NER period) with subsequent reviews moving to a 5 year cycle.

The regulation of Australian distribution companies within the NEM is moving from jurisdictional regulators to being undertaken by a single national body, the AER. The AER will be responsible for the establishment of future price controls for the distribution network companies once the current controls expire. However, the jurisdictional regulators will remain responsible for compliance and monitoring for the current set of price determinations. Periods for regulatory price setting are normally 5 years in the NEM areas, although only 4.5 years in Tasmania. This is likely to be standardized once all regions are regulated by the AER. The AER is not responsible for regulation of distribution companies in states outside the NEM, which covers Western Australia and the Northern Territory. The ERA is responsible for regulation in Western Australia with a price control period of 3 years.

As of 1 July 2008, the AER also took over responsibility for economic regulation of all gas and transmission distribution network pipelines in all states except Western Australia. The service provider (owner or operator) of covered pipelines need to comply with the provisions of the National Gas Law and Gas Rules. This would typically require the submission of an access arrangement including tariffs to the regulators, which includes an assessment of capital expenditure.1 While price control periods are typically 5 years there are some utilities where

1 There are some transitional exemptions and the scope of regulation will also depend on the definition

of the types of network. Some networks are exempt from this process depending on whether they are covered by the regulation while others have light handed regulation rather than requiring the full process.


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the price control periods run for much longer durations. Further details of these price control periods (which currently vary per jurisdiction) are provided below.

In Western Australia, the ERA remains responsible for regulation of covered pipelines and electricity networks. The state is in the process of implementing a modified version of the National Gas Law through the National Gas Access (Western Australia) Bill 2008, which will be the main document governing gas access arrangements in this region.

This section considers the approach that the AER has already used in transmission company determinations and intends to use in future distribution company determinations with specific references to asset management. In addition, the approach used by the ERA in Western Australia has been included as a comparator. There are some additional requirements from the state based technical regulators and state governments for asset management practices. However, as these are not explicitly used by the AER for assessment of utility plans in the NEM region and will vary per state and they have not been considered further in this analysis.

1.1 Characteristics of Utilities Affected

1.1.1 Number of Companies

Electricity

In electricity, there are regional companies in all states that are separately responsible for the transmission and distribution networks. There is normally one transmission company in each state (with the exception of NSW), but a number of major distribution businesses. This breaks down as shown in the table below.

Table 1: Transmission and Distribution Companies in Australia Area Transmission Companies Distribution Companies NSW (and ACT) TransGrid

Energy Australia EnergyAustralia Integral Energy Country Energy ActewAGL

Queensland Powerlink Energex Ergon Energy

Victoria SP AusNet Solaris (formerly AGL/Alinta) CitiPower Powercor SP AusNet (Eastern Energy) United Energy

Tasmania Transend Aurora Energy South Australia ElectraNet ETSA Utilities Western Australia Western Power Western Power2

2 There is an additional Government owned vertically integrated company (Horizon Power) that provides distribution services in Western Australia. The company supplies regional and remote customers with many areas having no interconnection and is not covered by the access arrangements regulation.


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Gas

In Australia, the National Gas Rules recognize that there is significant interconnection between states and that some transmission pipelines do not have significant market power and do not need to be regulated. This analysis focuses on the networks that are covered by regulation and will therefore need to submit investment plans to the regulator. This leaves ten major transmission pipelines in the NEM region and Western Australia with some states having up to three and others no regulated transmission pipelines3. The gas distribution businesses are normally covered by regulation with at least one regulated network in each state. The pipelines that are covered by regulation and distribution networks are listed below.

Table 2: Transmission Pipeline and Distribution Companies Area Transmission Pipelines Distribution Companies NSW (and ACT)

Central West (Marsend to Dubbo)

Central Ranges (Dubbo to Tamworth)

NSW Gas Networks (Alinta AGN)

Central Ranges System

Wagga Wagga distribution

ActewAGL Distribution (Canberra network)

Queensland Roma (Wallumbilla) to Brisbane

Carpentaria (Ballera to Mount Isa)

Dawson Valley Pipeline

Allgas

Envestra

Victoria Victorian Transmission Vic System (GasNet) Multinet

Envestra (Stratus)

SP AusNet Tasmania

Tasmanian Gas Network4

South Australia Moomba to Sydney5

South Australian distribution Western Australia Dampier to Bunbury

Goldfields Gas Kalgoorlie to Kambalda

Alinta Gas Networks

1.1.2 Geographic Areas Served

Electricity Companies

The charts below indicate the location of the major gas and electricity networks in the National Electricity Market (NEM) region. The first chart shows the transmission networks that exist in each of the states and the three interconnectors. This demonstrates the length of the single interconnected network that covers the NEM region, but also illustrates that

3 There are an additional 4 major transmission pipelines in Northern Territory only one of which is subject to regulatory control. 4 This pipeline is not currently covered by a regulatory price control. 5 Pipelines go between South Australia and Sydney so covers more that one state.


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geographically a large part of the state are rural and remote and therefore not part of the transmission network. The second chart shows the distribution company boundaries in the NEM market.

Figure 1: Transmission Networks in the AER Region

Source AER: State of the Energy Market 2008


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Figure 2: Electricity Distribution Network Operators in the AER Region


Western Power operates the South West Interconnected Network (SWIN) covering most of Western Australia with the regional and remote market supplied by Horizon Power. These are shown in the separate diagram below that illustrates the whole energy network for Western Australia. There are a number of private transmission/distribution networks in the region that have exemptions from the requirements of licensed participants.


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Figure 3: Energy Infrastructure in Western Australia

Source: Western Australia Office of Energy


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Gas Transmission Pipelines

The chart below provides an overview of the major gas transmission pipelines in Australia including both uncovered and covered pipelines. It also shows the main gas basins that exist in Australian and the key processing points that exist.

Figure 4: Major Gas Transmission Pipelines in Australia


The following figure shows the major gas distribution networks in Australia alongside the key transmission pipelines. This illustrates the large parts of the country that are not covered by a distribution network.


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Figure 5: Gas Distribution Network in Australia


1.1.3 Key Technical and Financial Statistics per Utility

Electricity Transmission Companies

The transmission companies for each region in the NEM market and Western Australia are listed below. There is no major transmission company in the Northern Territory.


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Table 3: Major Transmission Companies in Australia6

Company Region Line Length (KM) 06-07

Max Demand (MW)

Current Regulatory Period

Regulated Asset Base ($ Million Nominal)7

Investment Current Period ($M AUD

SP AusNet Victoria 6500 9062 2008/09 to 2013/14

2191 947

ElectraNet South Australia

5611 2942 2008/09 to 2012/13

1251 655

TransGrid NSW 12,489 13458 2004/05 to 2008/09

3013 1184

Energy Australia

NSW 1040 5484 2004/05 to 2008/09

636 230

Powerlink Queensland 12000 8589 2007/08 to 2011/12

3753 2418

Transend Tasmania 3645 2415 2004 to 2008/09

604 362

Western Power

Western Australia

6623 39618 2007 to 2009 1387 626

Electricity Distribution Companies

There are 15 major distribution companies in Australia and 13 of these are located in the NEM regions that AER regulates. These companies along with Western Power, which is the major distributor in Western Australia, are listed below.

Table 4: Major Distribution Companies in Australia


Customer Numbers


Asset Base ($ Million Nominal)9

Investment Current Period ($M 2007)

Energy Australia NSW 47144 1539030 2004-2009 4116 2455

Integral Energy NSW 33863 822446 2004-2009 2283 1733

Country Energy NSW 182023 734071 2004-2009 1375 1539

ActewAGL ACT 4623 146556 2004-2009 510 115

Solaris Vic 5579 286085 2006-2010 578 253

SP AusNet Vic 29397 573766 2006-2010 1307 755

United Energy Vic 12308 609585 2006-2010 1220 547

CitiPower Vic 6488 286107 2006-2010 991 529

6 Tables 3 to Table 10 have been sourced from AER State of the Market 2008 7 The RAB is set at the beginning of each regulatory period for each network. 8 Forecast figures from the Eastern Australia IMO 9 Asset valuation is the opening regulated asset base for the current regulatory period.


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Customer Numbers


Asset Base ($ Million Nominal)9

Investment Current Period ($M 2007)

Powercor Vic 80577 644113 2006-2010 1626 1008

ETSA Utilities South Australia

80644 781881 2005-2010 2468 810

Energex Qld 48115 1217193 2005-2010 4308 3011

Ergon Energy Qld 142793 736710 2005-2010 4198 2945

Aurora Energy Tas 24400 259600 2008-2012 981 575

Western Power WA 69083 925000 2006-09 1595 907

Gas Transmission Companies

This section provides an overview of the ten regulated gas transmission companies. It is interesting to note the very significant size differences between the companies in both line length and asset value.

Table 5: Major Regulated Gas Transmission Companies in Australia

Pipeline Region Line Length (KM)

Valuation ($ Million)10


Moomba to Sydney SA-NSW 2029 835 (2003) 2004-2009

Central West (Marsend to Dubbo) NSW 255 28 (1999) 2000-2010

Central Ranges (Dubbo to Tamworth)

NSW 300 53 (2003) 2005-2019

Victorian Transmission Vic System (GasNet)

Vic 2035 524 (2007) 2008-2012

Roma (Wallumbilla) to Brisbane Qld 440 296 (2006) 2007-2011

Carpentaria (Ballera to Mount Isa) Qld 840 n/a Light regulation only

Dawson Valley Pipeline Qld 47 8 (2007) 2007-2016

Dampier to Bunbury WA 1854 1618 (2004) 2005-2010

Goldfields Gas WA 1427 514 (1999) 2000-2009

Kalgoorlie to Kambalda WA 44 45 (2004) No access arrangement approved

10 Opening Regulatory Asset Base for the current regulatory period.


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Gas Distribution Companies

The major gas distribution companies are listed below. The NSW gas network is significantly larger (almost 100% larger) than its nearest rival in terms of the length of the mains.

Table 6: Major Gas Distribution Companies in Australia

Company Region Length of Mains (KM)

Through-put (PJA Year)11


Asset Base ($ Million 2007)12

Investment Current Period ($M AUD)

NSW Gas Networks (Alinta AGN)

NSW 23800 131.9 2005-2010 2088 518

Central Ranges System

NSW 250 Na 2006-2019 n/a n/a

Wagga Wagga distribution

NSW 622 1.4 2005-2010 47 8

ActewAGL Distribution (Canberra network)

NSW 3621 7.2 2004-2010 247 49

Multinet Vic 9513 61.4 2008-2012 888 251

Envestra (Stratus) Vic 9350 57.5 2008-2012 859 394

SP AusNet Vic 9140 71.3 2008-2012 955 343

Allgas Qld 2515 13.9 2006-2011 307 155

Envestra Qld 2261 5.3 2006-2011 235 100

South Australian distribution

SA 7377 29.1 2006-2011 851 204

Alinta Gas Networks WA 12157 31 2005-2009 708 708

Tasmanian Gas Network

Tas 683 Na Not covered 100 N/a

1.1.4 Ownership Structures

There is an interesting mixture of government owned and private network companies in Australia. Some states have privatized the network industries, while others have maintained public sector ownership. The ownership of the companies is listed below.

Electricity Transmission

The majority of transmission networks are still in government hands, whereas the opposite situation occurs for interconnectors, which are owned by the private sector as shown below.

11 2006 figures from AER: State of the Market 2007 12 Opening regulatory asset base adjusted to 2007 dollars. Tasmania figure is an estimate.


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Table 7: Ownership of Electricity Transmission Companies Owner Transmission Network NSW Government TransGrid

Energy Australia SP AusNet (Company 51% owned by Singapore Power) SP AusNet Powerlink (Qld Govt), YTL Power Investment, Hastings Utilities Trust

ElectraNet

Qld Government Powerlink Tasmanian Government Transend WA Government Western Power

Electricity Distribution Networks

Victoria and South Australia have privatized networks with ACT being 50% privately owned. The remaining distributors are all state government owned as indicated in the table below.

Table 8: Ownership of Electricity Distribution Networks Owner Distribution Network NSW Government EnergyAustralia

Integral Energy Country Energy

Cheung Kong Infrastructure/Hong Kong Electric Holdings 51%, Spark Infrastructure 49%

CitiPower Powercor ETSA Utilities

Qld Government Energex Ergon Energy

Jemena (Singapore Power International) Solaris (formerly AGL/Alinta) SP AusNet (listed company 51% owned by Singapore Power International)

SP AusNet (Eastern Energy)

ACTEW Corporation (ACT Govt 50%, Jemena 50%) ActewAGL Duet Group 66%, Jemena 34% United Energy Tasmanian Government Aurora Energy WA Government Western Power


There have been many changes in the ownership of gas pipelines over the last few years with APA Group taking a large holding in the regulated pipelines as shown in the table below.


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Table 9: Ownership of Regulated Gas Transmission Networks Owner Pipelines APA Group Moomba to Sydney

Central West (Marsend to Dubbo) Central Ranges (Dubbo to Tamworth) Victorian Transmission Vic System (GasNet) Roma (Wallumbilla) to Brisbane Carpentaria (Ballera to Mount Isa) Kalgoorlie to Kambalda

Anglo Coal (51%), Mitsui (495) Dawson Valley Pipeline DUET Group (60%), Alcoa (20%), Babcock and Brown Infrastructure (20%)

Dampier to Bunbury

APA Group (88.2%), Babcock and Brown Infrastructure (11.8%)

Goldfields Gas

Gas Distribution Companies

All the major gas distribution networks in Australia are privately owned with networks privatized from 1993-2006, while in NSW they have always been in the private sector. The current owners are listed in the table below.

Table 10: Ownership of Regulated Gas Distribution Networks Owner Gas Distribution Network APA Group Central Ranges System

Allgas Envestra (Cheung Kong Infrastructure 17%, APA Group 17%)

Envestra (Strata) Envestra South Australian distribution

Jemena (Singapore Power International (Australia)) NSW Gas Networks (Alinta AGN) Country Energy (NSW Govt) Wagga Wagga distribution ACTEW Corporation (ACT Govt 50%, Jemena 50%) ActewAGL Distribution (Canberra network) Duet Group 79.9%, BBI 20.1% Multinet SP AusNet (listed company, Singapore Power International 51%)

SP Ausnet (Westar)

BBI 74.1%, Duet Group 25.9% Alinta Gas Networks Powerco (BBI) Tasmanian Gas Network

1.2 Assessment of Utility Investment Plans

Electricity Transmission and Distribution Determinations by the AER

A review process for the revenue proposals of transmission companies is set out in the National Electricity Rules. This review process includes a number of iterative stages to make a determination which involves:

Pre-consultation; Revenue proposal and revised revenue proposal;


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Public consultation and submissions; and Draft and Final Decisions.

As part of the draft and final decision it is normal for the regulator to include assessment by a technical expert of the revenue proposal. This will involve the expert (and sometimes AER staff) meeting with the companies to inspect supporting information like planning documents, manuals and financial models and to discuss these documents with senior members of staff.

Key elements of the investment plans that can be investigated include the effectiveness of the operating practices and procedures and the asset management system and practices operated by the company. Asset management has been examined in many of the recent capital expense reviews and key elements of the asset management strategy will therefore be included in each revenue proposal produced by the transmission companies and made available for public consultation. In addition, the technical experts are likely to ask for further information and demonstration of this asset management policy as part of their review.

The AER is yet to make a final distribution determination, although the draft decision covering New South Wales has recently been released. The approach is similar to that adopted for transmission companies and is laid out in the NER. Key stages include:

Framework and approach paper (setting out AER’s likely approach); Submission of regulatory proposal and revised regulatory proposals; Public consultation; and Draft and final determinations (includes a pre-determination conference).

As with the Transmission rules, some of these are iterative processes with prescribed dates by when each of the subsequent activities need to take place. Prior to the submission of the regulatory process, the distribution networks and the AER will have agreed on the Regulatory Information Notice, which will specify the information that needs to be provided as part of the regulatory proposal.

There are currently proposals for investment plans that have been submitted by EnergyAustralia, Country Energy and Integral Energy. These proposals all makes substantive references to their asset management plans and strategies, which is a key element of the draft determination for the companies. All of these revenue proposals were available as part of the public consultation process that was run by AER.

The NER states that the AER must accept the forecast of required capital expenditures for both transmission and distribution companies if the costs reflect:

The efficient costs of achieving the capital expenditure objectives; The costs that a prudent operator would require to achieve the capital

expenditure objectives; and


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A realistic expectation of the demand forecast and cost inputs required to achieve the capital expenditure objectives.

A prudent operator would need an asset management plan in order to make decisions on the efficient costs needed to meet the capital expenditure objectives. The requirement for an asset management plan would therefore be essential in any capital investment plan.

Gas Transmission and Distribution Access Arrangements Decisions by the AER

The AER assumed responsibility for the regulation of gas transmission and distribution networks in July 2008 and no revenue decisions have yet been made. However, the process is consistent with that seen in electricity and is described at a high-level in the National Gas Rules. These Rules commenced operation on 1 July 2008 and govern access to the natural gas pipeline services. They outline the process that is typically followed for a full access arrangement proposal (which would cover capital expenditures) and include:

Pre-submission conference; Notification of submission of proposal and opportunity to comment; Access arrangement draft decision; Revision of access arrangement; Hearing on the access arrangement draft decision; and Access arrangement final decision.

Further details on the intended application of this process are contained in the Draft Access Arrangement Guidelines that were published in September 2008. These are due to be finalized in early 2009.

The National Gas Rules include the approach on capital expenditure and while not specifically mentioning asset management do state that:

“Capital expenditure must be such as would be incurred by a prudent service provider acting efficiently, in accordance with accepted good industry practice, to achieve the lowest sustainable cost of providing services”.

Based on previous jurisdictional submissions and the electricity requirements the demonstration of good industry practice is likely to require some form of an asset management plan. Previous jurisdictional review processes indicated the use of technical consultants to review the plans and it is anticipated that this will be part of the new process in the regulator makings its decisions and involve meetings and discussions with the companies. The Draft Access Arrangement Guidelines indicate that advice from the consultant may be used in making a decision.


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Electricity Transmission and Distribution Decisions by the ERA

The approval process for agreement to the access arrangement for Western Power (the only Network operator) is summarized as follows:

Submission of proposed access agreement (this is published by ERA for public submissions);

The ERA may publish an issues paper as part of public consultation; Draft decision paper and invite for further public submissions including the

opportunity for Western Power to submit a revised access arrangement; and Final decision by the ERA.

In certain cases there may be further need for an amended proposed access arrangement and further final decision. The ERA will normally use appropriate technical experts to assist with the review of the proposal.

The Access Code states that any new capital investment that is included needs to be shown that it does not exceed the amount that would be invested by a service provider efficiently minimizing costs, which requires acting in accordance with good electricity industry practice. This good electricity industry practice involves operation in accordance with the laws, codes standards, etc., and these contain requirements for asset management plans and this is examined further below.

The latest Western Power submissions to the ERA (1 October 2008) contained numerous references to asset management including a dedicated section on the approach to asset management and network development.

There is an additional process for large augmentation projects on the transmission network, but this has been ignored for the purpose of this assessment.

Gas Transmission and Distribution Decisions by the ERA

The ERA is in the process of implementing gas legislation that will closely match the National Gas Law and National Gas Rules used in the AER. The most significant change for Western Australia is that this introduces tight timeframes for future access arrangement revisions.

In the ERA guidelines (Gas Access Arrangements – Revision Process) they describe the process for approving the access arrangement as having three stages:

1) Stage 1 – Pre-lodgement consultation process – this is optional but will provide the opportunity for service providers to clarify key issues;


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2) Stage 2 – Lodgement of access documents, public consultation and draft decision for public submissions; and

3) Stage 3 – Second round of public submissions possible revised (and further revised) access arrangements and Final Decision by the ERA.

While asset management practices are not specifically mentioned in the guidelines, one of the subjects that is outlined for the pre-lodgement consultation process is the process for verification of the future capital expense forecast. This is likely to require an asset management plan to verify the need for capital expenditure that will be reviewed by the technical experts.

1.3 Regulatory Information Requirements

AER Electricity Transmission and Distribution Requirements

The AER has established regulatory submission guidelines for transmission companies, which were published in September 2007. These Guidelines and the associated Appendix list a number of requirements for information that needs to be provided. Appendix A of the submission guidelines on cost information has a sheet called “Commentary for Forecast Capex”. This includes a requirement to provide details of the overall asset management strategy plan, although no formal definition or scope of what this plan should consist of are included in the guidelines.

Within the Appendix to these guidelines, there is a requirement for forecast and historic operating expense spent on asset management. This includes the scope for asset management support, which are the operational activities to support the strategic development and ongoing asset management of the network. This asset management support has five major sub-elements; grid planning, project support, network customer and regulatory support, IT support and operational support. The NER specifically requires transmission companies to ensure their revenue proposals comply with the submission guidelines.

These submission guidelines only refer to transmission companies and not to distribution businesses. However, as part of the distribution determination process the company will have been issued a Regulatory Information Notice requiring information on many aspects of their capital plan including asset management. The Regulatory Information Notice is company specific and is therefore confidential, although consideration is being given to production of a public version of this document. The Regulatory Information Notice would be agreed in consultation with the companies being assessed and include pro forma templates and guidelines as to the information required. The National Electricity Rules specifically require distribution companies to comply with the requirements and provide the information required by any Regulatory Information Instrument, which includes the Regulatory Information Notice.


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The AER is currently consulting on their annual reporting requirements for distribution companies; a number of which relate to a register of assets. However, these do not specifically cover asset management plans.

AER Gas Transmission and Distribution Requirements

The draft access arrangement guidelines were published in September 2008. This includes a check list of all of the data items required as part of an access arrangement submission. These guidelines do not specifically include any reference to asset management, although the requirement in the rules for operating in accordance with good industry practice could be seen as a sufficient obligation to have asset management procedures.

ERA Electricity Distribution and Transmission Requirements

The Electricity Networks Access Code provides details of the submissions, including timescales for each part of the submission process. In addition, there are also guidelines for providing access information that have been provided by the ERA.

These guidelines require forecasts of capital expenditure to include (not a complete list):

Details of the methods used to develop forecasts; Forecasts of load growth and how they are derived; Description of asset management plans and methods and assumptions used to

forecast capital expenditure in accordance with these plans; and Explanation of material variations in the forecast of capital expenditure from

historic levels of, and trends in, amounts of capital expenditure.

While asset management plans are required, the guidelines do not state any requirements about what should be considered within these plans.

ERA Gas Distribution and Transmission Requirements

The ERA has produced guidelines in a Gas Access Arrangements Revision Paperm, which outlines times and dates for the consultation process and the types of information that it anticipates will be provided as part of the process. This includes (of potential relevance to asset management):

Electronic copies of models and methodologies and justification for these; All data used in calculations; Details of key assumptions; and Copies of audit reports on historical capital expense and operating expense.

The document does not prescribe exactly what information will be required, but indicates that this will be finalized during the pre-lodgement consultation process.


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1.4 Explicit Asset Management Requirements

As the AER region covers a number of states with separate legislation, the description of explicit asset management requirements have focused only on the national rules. There are some additional references to asset management in state legislation and licensing, but these are not consistent across regions and will not be part of the AER’s determination of the capital investment plans.

AER Electricity Transmission and Distribution Requirements

There is no specific reference to asset management in the NER. The transmission guidelines do require an asset management plan, although these guidelines do not provide specific details on tools and systems required. The Regulatory Information Notice will require distribution companies to provide an asset management plan, but these are company specific and confidential.

AER Gas Transmission and Distribution Requirements

No specific reference to asset management requirements are contained in either the rules or the access arrangement guidelines.

ERA Electricity and Gas Transmission and Distribution Requirements

In Western Australiam, there is an asset management requirement for all electricity, gas and water service licensees (except retail and trading) to provide for an asset management system. This is specified in the Electricity Industry Act 2004 and the Energy Coordination Act 1994 and has been turned into a license condition.

The specific requirement for the licensee is to notify the ERA of its asset management system for its distribution/transmission system within 2 days from the later of the commencement date or from the completion of the distribution/transmission system (i.e., almost from the start of the operation of the network there is a license requirement to have an asset management system in place). The licensee must also notify the Authority of any material change to this system with 10 business day of this change.

In order to demonstrate this asset management system the licensee has a responsibility for reporting on the effectiveness of their asset management system within 24 months of the commencement date and every 24 months thereafter (a time period that can be shortened by the ERA). The report on the effectiveness of the asset management system needs to be undertaken by an independent expert, who needs to be approved by the ERA.

The licensee (and the expert) need to comply with the relevant aspects of the Authority’s standard guidelines dealing with the asset management system covering the hiring of the expert, scope of the review, conduct of the review and results of the review.


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Audit Requirements

The ERA has published Audit Guidelines: Electricity, Gas and Water Licenses. This provides a detailed guide on what the auditor should examine when produceing the report on the Asset Management System. This requires 12 elements of the asset management system to be rated for effectiveness according to an agreed scale. These elements are:

1) Asset planning;

2) Asset creation and acquisition;

3) Asset disposal;

4) Environmental analysis;

5) Asset operations;

6) Asset maintenance;

7) Asset Management Information System (MIS);

8) Risk Management;

9) Contingency planning;

10) Financial planning;

11) Capital expenditure planning; and

12) Review of the Asset Management System.

It should be noted that the review is backward looking and considers the procedures in place during the period of the audit. The report can include recommendations, which the Authority could decide to serve notice on the licensee to implement by some future date, if the approach is not seen as satisfactory. The audit guidelines also allow the ERA to bring forward the date of the next audit. This route was taken after the latest review of Western Power with the next review requested in 19 months rather than the standard 24 months.

Guide for Small Licensees

In addition to the audit guidelines, the ERA has also published a guide for preparing the financial information component of the asset management plan designed to help smaller licensees. This guide notes that the asset management system should specify the measures


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being taken by the licensee for the proper maintenance of assets used in the supply or provision of electricity or gas and the construction, operation and disposal of these assets.13

A key part of the asset management system is the asset management plan. The ERA guide for asset management describes this plan as:

“a plan developed for the management of one or more infrastructure assets that combines multi-disciplinary management techniques (including technical and financial) over the lifecycle of the asset in the most cost-effective manner to provide a specified level of service. A significant component of the plan is a long-term cash flow projection for the activities.”

This definition is taken from the International Infrastructure Management Manual – Version 3.0 2006. This document is seen by the ERA as providing a best practice framework for the management of infrastructure assets by small electricity and gas licensees.

In addition to the license requirements, there are two explicit references to asset management in the Electricity Networks Access Code. These are in relation to the need for ring-fencing arrangements rather than the capital investment plans. Within the guidelines for the access arrangement it does state that the forecasts of capital expenditure must be accompanied by:

“A description of asset management plans relied upon to derive the forecasts of capital expenditure for the purposes of replacing assets and maintaining service levels; and details of the methods and assumptions used to develop the forecasts of capital expenditure in accordance with asset management plans.”

1.5 Relevant Regulatory Instruments

1.5.1 Laws and Regulations

As with the previous section, the analysis has focused on laws and regulations introduced by the economic regulator rather than any jurisdictional regulator.

Electricity Companies Regulated by the AER

Electricity revenue regulation for all states in the NEM is now undertaken by the AER. The AER is a separate legal entity and is part of the Australian Competition and Consumer Commission. It is currently responsible for economic regulation, but this is due to expand to cover non-economic distribution and retail functions in 2009.

The AER’s current functions are focused on regulating the transmission and distribution sectors of the NEM. Its regulatory functions and powers are conferred upon it by the National Electricity Law and National Electricity Rules. The AER’s key responsibilities relevant for transmission and distribution regulation as part of these laws and rules include:

13 Description taken from ‘A Guide for Preparing the Financial Information Component of an Asset

Management Plan’ July 2006 – ERA, Licensing, Monitoring and Customer Protection Division.


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Regulating the revenues of transmission and distribution companies; Monitoring compliance with the national electricity law, national electricity

rules and national electricity regulations and investigating breaches; Instituting and conducting enforcement proceedings against relevant market

participants; Establishing service standards for electricity transmission network service

providers; Establishing ring-fencing guidelines for business operations with respect to

regulated transmission services; and Exempting network service providers from registration.

The regulation of the electricity transmission and distribution companies is performed in accordance with the electricity laws.

Gas Companies Regulated by the AER

Since 1 July 2008, gas companies in all states (except WA) are regulated by the AER under the National Gas Laws and National Gas Rules. The function and powers of the AER for economic regulation of gas transmission and distribution pipelines derived from these laws and rules include:

Approval of certain access arrangements submitted by service providers under the NGL and NGR;

Review of annual reference tariff variation; Annual monitoring of compliance of service providers' obligations; Undertaking enforcement functions as required under the NGL and NGR; Hearing disputes on access of relevant pipelines; Approval of competitive tendering processes; and Other functions and powers under the NGL and NGR.

Electricity Companies Regulated by the ERA

Western Power is currently the only distribution or transmission company that has a covered network regulated by the ERA. This network is regulated by the ERA is accordance with the Electricity Network Access Code and the key responsibilities of the ERA include:

Agreement of access arrangement of the covered network; Approval of technical rules for standards, procedures and planning criteria; Making of price determinations; Agreement and monitoring of service standard benchmarks; Application of Regulatory Test for major augmentation proposals; Determination of preferred methodology for calculating WACC; and Establishing, monitoring and enforcing ring-fencing rules.


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Gas Companies Regulated by the ERA

The ERA is responsible for regulation of gas network companies under the National Third Party Access Code for Natural Gas Pipeline Systems. The objective of the code is to establish a framework for third party access to pipelines that prevent abuse of market power, encourages competition and facilitates the development of a competitive pipeline. The code also provides rights of access to natural gas pipelines on conditions that are fair and reasonable and provides for resolution of disputes. The code obliges the owner or operator to lodge an access arrangement with the relevant regulator (in this case ERA) and provides a process to accept, reject or amend this access arrangement. Other important responsibilities as part of the code includes:

Coverage (form of regulation that needs to be applied); Applicable services and reference tariffs; Pricing principles; Ring-fencing; Information disclosure; Binding arbitration; and Specific timelines for all processes.

1.5.2 Codes, Rules, Filing Guidelines/Requirements

In this section an overview of the approach taken to regulation and the rules and timelines needed for submission of plans (including asset management plans) is provided.


The AER applies a revenue cap for each of the transmission businesses in the NEM in response to revenue proposals submitted by each of the transmission companies. The revenue proposal is derived according to a specified post tax recovery model and the submission guidelines. The AER is obliged in the rules to prepare the post tax recovery model and the submission guidelines.

Any revenue determination for a transmission company needs to last for a regulatory control period of not less than 5 years and establishes the maximum allowable revenue a network can earn during the regulatory period. The AER is obliged under the terms of the rule to use a building block approach covering the components that make up the costs of a transmission business. The AER is also responsible for approving the pricing methodologies of the transmission companies in accordance with the NER.

In order to clarify the information and approach that is required from each transmission or distribution) business, a series of regulatory guidelines, models and schemes have been produced. These guidelines are separate for transmission and distribution but for both types of companies include:


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Post tax revenue model – determine distribution business annual regulated revenue;

Roll forward model – to determine RAB for each network; Efficiency benefits sharing schemes; Service target performance incentive scheme; and Cost allocation guideline.

Additional transmission guidelines include pricing methodology, ring-fencing, information and a regulatory test. This test is a decision making tool used to assess proposed augmentation projects for economic efficiency. The transmission guidelines also include submission guidelines specifying the information that needs to be provided.

In determinations made since 2005, the AER has allowed transmission businesses discretion on the timing and how they spend their investment allowance. To encourage efficient spending, the business will keep a proportion of any savings against their investment allowance. There is a service standard incentive scheme to ensure that cost savings are not achieved at the expense of service quality.

In distribution, the NER requires the use of an incentive based approach, but allows the regulator to choose whether a price or revenue control is applied. The historic jurisdictional application of control means that there is a range of different approaches that have been applied as shown in the figure below. Each approach will involve the setting of a ceiling on the revenues or the prices that a distribution company can earn during the regulatory period with a building block approach, generally used to determine the revenue or price ceiling. The building blocks for both transmission and distribution companies will include operating expenses, asset depreciation costs, taxation and a commercial return on capital.


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Figure 6: Current Forms of Incentive Regulation for Distribution Companies


Regardless of the approach applied the regulator needs to forecast the revenue that a distribution business would require if it was operating efficiently. This needs to include investment forecasts and operating expenditure allowances. Any regulation will also provide incentives for the distribution company to manage efficiently and reduce costs while still meeting service standards.

The typical time frame needed for both distribution and transmission regulatory determination processes can be seen from the current NSW activities. It should be noted that prior to the submission date of the revenue proposal (for TransGrid) and regulatory proposals from the distributors there were pre-consultation discussions with the AER.

The timetable, which is now being observed, is indicated in the table below. After receiving the initial submissions, a consultant was appointed to perform the review as an input into the draft decision. This included a bottom-up review of program and units costs and benchmark assessments.


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Table 11: Latest Dates for Transmission and Distribution Determinations by AER Activity Date Receive TransGrid revenue proposal and NSW Distributors proposals14 TransGrid (31 May) and NSW

Distributors (2 June 2008) Public Forum 30 July 2008 Submissions close 8 August 2008 Release AER’s draft decision (draft distribution determination) and consultants reports

30 November 2008

Public forum on decisions/determinations December 2008 Distribution companies and TransGrid opportunity to lodge revised proposal

January 2009

Submissions close February 2009 AER final decision (final distribution determination) April 2009

The NER provides for a contingent allowance for transmission projects, which are foreseen at the start of the period, but for which there is significant uncertainty on cost and timing. In addition, there is an option for the transmission company during a regulatory control period to revoke and substitute a revenue determination if certain events occur. There are also cost pass through provisions (which can be positive or negative) for both transmission and distribution networks and network support pass through provisions for the transmission company.


The form of control applied by the AER will depend on whether the pipeline is covered and whether it is suitable for light regulation. However, light regulation is only considered for point-to-point transmission pipelines with a small number of users who have countervailing market power.

The pipelines that are covered and subject to full regulation need to have an access arrangement in place that contains price and revenue terms, as well as access condition for reference services provided by the pipeline. A new pipeline has to provide an access arrangement proposal to the AER within 3 months of becoming a covered pipeline. The access arrangement needs to provide the terms and conditions for third party access and contain at least one reference tariff.

It is expected that most network operators will use a building block approach to determine total revenues. This will need to cover operating expense costs, asset depreciation costs and a return on capital.

There have been no gas determinations by the AER so the timetable is unproven. However, the draft access arrangement guideline for gas does provide an expected timetable and this is shown in the table below. Expert consultants are likely to advise the AER as part of the draft decision.

14 Energy Australia submitted proposals for both its transmission and distribution networks.


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Table 12: Timetable for Access Arrangement (Source: Draft Access Arrangement Guideline) Phase of the Decision Making Process Time from Proposal Submission

Date Phase 1 Pre-Consultation Commencement of pre-consultation process - 6 months Phase 2: Proposal Proposal submitted Proposal published +30 business days Submissions due date +50 business days Phase 3: Draft Decision AER draft decision released +80 business days Submission of revised proposal by service provider +95 business days Submissions due date on draft decision + 115 business days Phase 4: Final Decision Final Decision released +135 business days

Access arrangements for a full regulation pipeline do not expire. They cease to have effect if coverage is revoked or a light regulation determination is made. However, a service provider for a full regulation pipeline must submit an access arrangement revision proposal to the AER on or before the review submission date15. A service provider also has the option in the NGR of submitting a revised access agreement prior to the review submission date.


The ERA regulates electricity networks according to the Electricity Networks Access Code, which seeks to promote economically efficient investment in the use of electricity networks. The code allowed for the first access arrangements to be complete after 3 years, which is the current review cycle that the ERA and Western Power are working on. Subsequent review cycles are due to last 5 years.

The code prescribes the content of an access arrangement proposal that must be provided in order to provide the basis for third party access to the network. This access arrangement must16:

Specify one or more reference services; Include standard access contracts; Include price controls; Include pricing methods; Include a pricing list; Include an application and queuing policy; Include a capital contributions policy;

15 The submission dates specified will have been specified in the previous access arrangements proposals. 16 This is a subset of the full list.


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Include efficiency and innovation benchmarks; and Include provisions dealing with:

– submission of proposed revision; and – trigger events.

The tariff related elements are of most significance to this report and impact on the price controls, pricing methods and current lists. This requires calculations for network valuation, capital expenditure, operating expense, demand forecasts, rate of return, price controls, etc.

The timeline for access arrangement decisions is best understood by looking at Western Power’s latest proposed revisions to the access arrangements which were submitted on 1 October 2008. (Note – dates can be extended subject to provision in the Access Code). These dates were published in the Issues Paper produced by ERA on the 5 November 2008.

Table 13: Timetable for Electricity Access Arrangements in Western Australia Activity Date Receive Western Power proposal 1 October 2008 Issues paper produced 5 November 2008 Public submissions close 19 November 2008 Draft Decision 16 January 2009 Second round public submission on draft decision 16 Feb 2009 Final decision. 31 March 2009 If required, the following extended process is available: Submission of amended proposal by Western Power 28 April 2009 Further final decision 19 May 2009 Commencement of revised access arrangement 1 July 2009

The existing access arrangement continues in effect from the access arrangement start date until the network ceases to be a covered network or a revised access agreement is introduced. The Network Access Code provides for the access arrangement to contain trigger events that allow for submission of revisions to the ERA. The ERA can also vary the price control in an access arrangement for a number of reasons, including: if it was based on materially false and misleading information, or if a material error or significant unforeseen development has occurred that could not have been controlled or prevented by the service provider.


All covered pipelines need to have an access arrangement in place and agreed with the regulator. This requires the access arrangement proposal to cover at least the following elements:

Services policy – services offered with possibility of subsets being available; Reference tariff – operates as a benchmark for other services; Terms and conditions; Capacity management, trading and queuing policies;


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Extension/expansions policy; and Review date.

The Reference Tariffs are set on the basis of the sales of all services delivering a certain amount of revenue (Total Revenue) over the period for which the Reference Tariffs apply. There are three different methodologies for determining Total Revenue, all of which will need calculations of costs and therefore some justification of capital expense and operating expense costs.

The ERA is currently in the process of introducing new legislation that will reflect the National Gas Rules and National Gas Laws that have been implemented in the rest of the country. One of the key changes will be the tighter time frames required. This was used for the latest timetable published in the Authority Guidelines for the Access Arrangement Revision Process produced in May 2008. The earliest timetable applies to the Mid West and South Gas Distribution System and the Goldfields Gas Pipeline and is as follows (key milestones only):

Table 14: Timetable for Gas Access Arrangements in Western Australia Activity Date Pre-Lodgement Consultation process 1 July 2008 Lodgement of Access Arrangement Information 31 March 2009 First round of Public Submission due 25 May 2009 Draft Decision Paper 22 July 2009 Revised Access Arrangement submission 12 August 2009 Public Hearing if requested 14 August 2009 Second round of public submissions due 9 September 2009 Discussions ERA, submitting parties and service provider 10 September – 5 November Re-submission of Access Arrangement (if necessary) 12 November 2009 Final decision made. 4 December 2009

It is anticipated that similar arrangements for re-submission of access arrangements will apply to those existing under the NGL once the new legislation is passed.

1.5.3 Regulatory Standards, Procedures or Guidelines


Each of the transmission companies are obliged to submit a revenue proposal, a proposed negotiating framework, and a proposed pricing methodology to the AER 13 months prior to the end of the current regulatory period. This revenue proposal has to be prepared using the post tax revenue model and must comply with the Submission Guidelines produced by the AER. There are a number of additional guidelines and models that the transmission company is expected to follow. The transmission company does have the opportunity to revise any proposal within 30 days of the draft decision.


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Distribution companies need to submit a regulatory proposal to the AER at least 13 months before the distribution determination. This needs to comply with the requirement of any regulatory information instrument. The AER has produced a number of guidelines and models (including the post tax revenue model and roll forward model) to assist distribution businesses, but there are no published submission guidelines. For any services that are classified as direct control services the NER states a building block proposal needs to be provided. The distribution company can resubmit their regulator proposal within 30 days of the draft determination.

It should be noted that the regulatory periods (start and end dates) are different for the transmission and distribution companies so there is not a single date when they are all going through the process.

Where more than one distribution system is owned by the same service provider there is still a need for a separate regulatory proposal to be submitted for each distribution system. This need for multiple submissions is the same in transmission, where a transmission total revenue cap applies to a system and not to a service provider.


The approach required by gas companies will depend on whether the network is covered by regulation or whether a light handed regulation approach has been applied. This report has focused on those covered by regulation and needing to submit a full access arrangement.

These covered networks require the gas service providers to submit access arrangement proposals along with access arrangement information. This needs to be provided on or before the review submission date of the applicable access arrangement. The access arrangement information needs to provide information that is necessary for users and prospective users to:

Understand the background to the access arrangement or the access arrangement proposal; and

Understand the basis and derivation of the various elements of the access arrangement or the access arrangement proposal.

If the access arrangement decision indicates that revision of the access proposal is necessary then the AER may fix a period for the gas company to revise the decision. This will be not less than 15 workings days from the decision.


The Electricity Networks Access Code states that the service provider of a covered network (currently Western Power) needs to submit a proposed access arrangement and access arrangement information to the Authority by the submission deadline. This access arrangement information needs to enable the Authority, users and applicants to:


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Understand how the service provider derived the elements of the proposed access arrangements; and

Form an opinion as to whether the proposed access arrangement complies with the code.

The service provider will have the opportunity to respond to the draft decision within 20 business days, which includes the opportunity to resubmit the access arrangement and access arrangement information.


For existing covered pipelines, the Gas Pipelines Access (Western Australia) Act requires the Service Provider to submit revisions to the Access Arrangement and the applicable Access Arrangement Information by the Revision Submission Date.

The gas companies will have the opportunity to respond to the draft decision and resubmit the access arrangement and access arrangement information. The timescales for this are indicated and will become consistent with the NGL and NGR, which will be at least 15 business days.

1.6 Regulatory Guidance to Utility Companies

1.6.1 Guidelines for the Preparation of Asset Management Plans

Electricity and Gas Companies Regulated by the AER

As the earlier sections have indicated there is little in the way of prescribed requirements for asset management. There is no particular asset management standard that has been adopted by networks and it seems unlikely that there will be one in the near future. While some networks have adopted the PAS 55 standard, others believe it to be inappropriate. The AER at this stage does not prescribe any particular standard that needs to be followed. Some of the companies are also complying with jurisdictional policies for asset management, which may govern the policies they adopt.

There is no explicit regulatory guidance regarding the preparation of asset management plans underlying a regulatory submission. The transmission guidelines do require an asset management plan, although no details are specified as to what tools and systems are required. For the distribution business, there is a Regulatory Information Notice that requires companies to provide an asset management plan, but it does not specify a preferred asset management standard to be followed.

There is no specific guidance from the AER for gas networks’ asset management plans even in the access arrangement guidelines.

Electricity and Gas Companies Regulated by the ERA


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The ERA has in place a specific asset management requirement for all electricity, gas and water service licensees (except retailing and trading) to provide for an asset management system. In their assessment of access proposals for the companies it would be anticipated that the asset management systems developed to meet this license requirement would be a key part of the capital investment plans.

Two documents are important in providing guidance on what needs to be in the asset management plan. These are:

1) The ERA: Audit Guidelines: Electricity, Gas and Water Licenses; and

2) The “Guide for Preparing the Financial Information Component of an Asset Management Plan”.

A description of both of these guides is contained in the earlier section. The audit guidelines state requirements rather than a specific asset management standard that has to be applied. While the guide for smaller participants does not mandate any standard it does use definitions from the International Infrastructure Management Manual Version 3.0 2006. This document was suggested as a best practice framework for the management of infrastructure assets by small electricity and gas licensees.

It is interesting to note the steps that the WA organizations have taken to meet the requirement in the audit guidelines. All Western Power’s asset management systems and processes have been quality certified to ISO 9001 and the Network Performance Branch of its customers service division has modeled the asset system on the requirements of PAS 55-1 Specification for the optimized management of physical infrastructure assets. This was seen by the auditor as in line with global best practice.

1.6.2 Investment Plan Requirements for Regulatory Submissions by Utilities

Electricity Transmission Regulated by the AER

The NER states that the revenue proposal needs to include total forecast capital expense expenditures, which need to comply with the requirements of the submission guidelines and be broken down for each regulatory year.

A key part of these submission guidelines are the spreadsheets that the transmission companies need to complete and, in particular, the guidelines on what should be provided for forecast capital expense expenditures. These guidelines and example sheets are provided below. Some of these guidelines, such as the requirement for details of the asset management strategy/plan, are not specific. The instructions indicate that much of the information does need to be broken down by project to allow further analysis.


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Figure 7: Submission Guidance for Forecast Commentary on Capital Expenditure

This pro forma is designed to provide context and background for the quantitative forecast capex templates, by specifying matters that the AER will take into account in assessing the TNSP’s proposed expenditure.

Table 4.3 provides a column where reasons for the project can be provided. This pro forma provides the opportunity for more detailed reasons to be given for factors influencing the proposed spend, including load growth, planned generation and the range of foreseeable scenarios and their probabilities of occurring.

The commentary should address the following: >The theme sets upon which the proposed capex spend is based

> The scenarios derived from the above theme sets and their relevant probabilities. > Project specific information in addition to the cost information provided in the forward capex templates. In addition, the TNSP is requested to provide: >Details of its capital expenditure and approvals processes. >Details of its overall asset management strategy/plan. >Relevant Annual Planning Reports. >Consultants’ reports on the probabilistic methodology adopted, its assumptions, inputs, and detailed information on the outcomes.

Figure 8: Submission Guidelines for Forecast Capex by Asset Class

4.2 FORECAST CAPEX by asset class

$ million, real (as of year 6) Year 6 Year 7 Year 8 Year 9 Year 10 TOTALAsset class

SecondarySwitchgearTransformersReactiveTransmission LinesEstablishmentCommunications (buildings, towersand site infrastructure)Communications (other assets)EasementsLandNetwork Switching CentreITBuildingsVehiclesOther Business support

TOTAL CAPEX

Home Link to Capex Instructions - Table 6.3


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Figure 9: Submission Guidelines for Forecast Capex by Asset Category

4.1 FORECAST CAPEX by project category

$ million, real (as of year 6)

Year 6 Year 7 Year 8 Year 9 Year 10 TOTAL

NON-LOAD DRIVEN Replacements

Security/Compliance

Other

NON NETWORKBUSINESS IT Information Technology

SUPPORT THE BUSINESS Buildings

Motor Vehicles

Other

TOTAL FORECAST CAPEX

HomeLink to Forecast

Capex Instructions - Table 6.3

NETWORK

Project Category

May expand these categories

In addition to the submission guidelines for the reset process, the transmission companies also have to comply with Information Guidelines as part of production of certified annual statements. These certified annual statements can be used to:

Monitor, report on and enforce compliance with the total revenue cap; Monitor, report and enforce compliance with the cost allocation

methodology; Input on the financial and operational performance of the transmission

companies to inform AER’s decision making for the making of revenue determination to apply in future regulatory control periods; and

Monitor and report on the performance of the transmission company under any service target performance incentive scheme.

In their final decision, AER indicates that one of their objectives is to reduce the regulatory burden on transmission companies by collecting much of the revenue reset information on an annual basis.

The information guidelines are complemented by a spreadsheet on the information that needs to be provided by each transmission company. This includes information on historic capital expenses by asset class and a commentary on the historic capital expenses. In addition, there is a requirement for an asset aging schedule.


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Electricity Distribution Regulated by the AER

The high-level requirements in the NER for distribution are similar to transmission. However, distribution businesses need to comply with the relevant Regulatory Information Instrument (which will include the Regulatory Information Notice) rather than the submission guidelines. These instruments are company confidential and not therefore in the public domain. However, it is likely that similar requirements will exist to those required for the transmission company.

Consideration of what needs to be in an investment plan, can be seen by the AER’s approach to its first draft determinations for Distributors. This document states that the AER’s approach to assessment has been to determine and examine whether:

their governance frameworks, capex policies and procedures are likely to result in investment decisions, on which the capex proposals are based, that are consistent with the capex objectives;

the methods and assumptions used to develop each capex proposal, including demand forecasts and estimates of unit costs, are robust and reflect a realistic expectation of the demand forecasts and cost inputs required to achieve the capex objectives;

estimates of real cost escalators and their application reflect a reasonable expectation of input cost forecasts;

the projects and programs that form part of the regulatory proposals generally reflect the capex criteria, including with respect to their scope, timing and costs; and

the capex programs are deliverable and are therefore commensurate with what a prudent DNSP would require to achieve the capex objectives.17

While this is similar to the approach taken by the AER from transmission, the application of the approach is different as the characteristics of distribution networks, particularly the larger number of small projects, means it is not feasible for the AER to undertake a detailed review of each project. More reliance has therefore been placed on review of the distribution companies’ policies and procedures, as well as underlying assumption. The AER (assisted by the consultant) has also paid more attention to general factors like trends in age, faults, etc., and methods (e.g., expenditure modeling) and deviation from historical expenditure.

This reliance on higher level information suggests more detail would be required on the asset management policies and how they have been applied as part of the investment plan.

The AER has recently (August 2008) published an issues paper on annual information reporting requirements for Distribution companies. The AER intends to publish a Regulatory Information Order (RIO) for annual publication of data. The AER intends to use this information to assist in the assessment of future regulatory proposals by distribution 17 The capital expense objectives reflect the need to meet the expected demand, comply with regulatory objectives and maintain the quality, reliability and security of supply.


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companies and for making distribution determinations. It is intended to be complementary to the Regulatory Information Instruments that are currently used to gather information on distributors. There are a number of proposed templates that are of particular interest to this assignment.

There are a number of capital expense templates that have been constructed (by asset type and cost driver) which will allow the AER to see the relationships between different drivers of costs and expenditure on asset types. This will improve the AER’s ability to assess revenue forecasts based upon predicted drivers of cost. An example of the proposed capital expense template is shown in the table below.


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Figure 10: Capex Template for Annual Reporting Network extensions ($000)

total

lines and cables overhead underground overhead underground overhead underground

CBDurban

rural shortrural long

substations and transformersCBD

urbanrural

buildings, land and easementscommunications

metersother system assets

public lightingTotal $ -

Increased load management ($000)total


CBDurban



urbanrural




Renewal/replacement ($000)total


CBDurban



urbanrural




Service improvement ($000)total


CBDurban



urbanrural




$ -

Table 2: Non-system asset expenditure ($'000)

Table 3: Total capex

Total capex $ -

cost category

other non-system assets

buildingsland

furniture, fittings, plant & equipmentmotor vehicles

Total system asset expenditure

distribution LVdistribution HVsubtransmission

subtransmission distribution HV distribution LV

subtransmission distribution HV

$ -

share of corporate assets

dollar value ($000)IT systemscost category

subtransmission distribution HV distribution LV

distribution LV

$ - Total non-system capex

$ - Non-system assets

dollar value ($000)System assets


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It is proposed that distribution businesses will provide the AER with asset schedules and supporting papers that will be disaggregated. A key report in this area focuses on asset aging, which is required to assist the AER with its assessment of forecast expenditure against operating and capital expenditure objectives. This requires a breakdown of the value of the distributor’s assets by asset class and remaining useful asset life periods as at the end of the latest regulatory year.

Figure 11: Template for Asset Ageing Schedule for Distributors

Total 1 to 2 3 to 4 5 to 6 7 to 8 9 to 10 11 to 15 16 to 20 >20

$'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000

lines and cablesSubtransmission

Distribution HVDistribution LV

substations and transformers

SubtransmissionDistribution HVDistribution LV

buildings, land and easements

communicationsmeters

other system assets

public lightingTotal $ - $ - $ - $ - $ - $ - $ - $ - $ -

Useful life remaining (years after regulatory accounting date)

There is also a detailed template arranging operating expense into maintenance expenditure, operating expenditure and other expenditure.


The regulatory asset base for a gas company is the opening capital base plus forecast conforming capital expenditure, which represents the investment plan for the business. This conforming capital expenditure needs to be prudent, which is defined as capital expenditure that “would be incurred by a prudent service provider acting efficiently in accordance with accepted good industry practice, to achieve the lowest sustainable cost of providing services”.

In addition, the capital expenditure needs to be justifiable, which needs to meet one of the following criteria from the gas rules (summarized in the access arrangement guidelines):

“the overall economic value of expenditure is positive (economic value test); the present value of the expected incremental revenue exceeds the present

value of the capital expenditure (incremental revenue test);


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the capital expenditure is necessary to: maintain and improve the safety of services; maintain the integrity of services; meet regulatory obligations; or continue to meet current demand (safety and integrity test); or

the capital expenditure is an aggregate of two parts – one of which satisfies the incremental revenue test and the other meets the safety and integrity test.”

Together, these requirements will require a detailed asset management plan, particularly with the third bullet requiring capital expenditure to be necessary. The requirements also state that where possible capital expenditure should reflect relevant asset classes that comprise the capital base.

At this stage there are no spreadsheet templates that break down the information required in the capital expenditure plan and therefore, no specific asset management requirement.


The ERA has produced “Guidelines for Access Arrangement Information” that contains a number of requirements for financial information for capital expenditure. Any forecasts of capital expenditure need to be disaggregated and broken down into whether they are covered/excluded transmission or distribution services or whether they are other businesses and services.

A further division is required within each business segment indicating the reason for the expenditure as:

Growth – increasing the capacity of assets or new assets; Asset replacement and renewal; Improvements in services; Compliance (meeting regulatory obligations); and Corporate – capital expenditure for corporate activities.

These forecasts of capital expenditure need to include:

Details of the methods used to develop the forecasts; Forecasts of load growth used in the forecast; Descriptions of asset management plans relied upon to derive the forecast of

capital expenditure for the purpose of replacing asset and maintaining service levels and details of the methods and assumptions used to develop the forecast of capital expenditure in accordance with asset management plans;

Description of regulatory obligations in service standards that lead to forecast expenditure;

Description of consideration of consumer preference that give rise to forecast expenditure;


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Explanation of material variance in expenditure from historic levels; and Justification of why the expenditure is expected to meet the new facilities

investment test or the test being applied to the capital base.

In addition to these requirements, the ERA also supplies Pro Forma statements that need to be completed by the electricity company and these are detailed below.

Figure 12: Pro Forma for Forecast Capital Expenditure by Asset Class


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Figure 13: Pro Forma for Forecast Capital Expenditure by Reason


The Authority Guidelines for the Gas Access Arrangements Revisions Process indicate the information that needs to be provided as part of the access arrangement and much of this will relate to the investment plans. This includes:

Electronic copies and justification of models and methodologies; All data used in calculations; Details of key assumptions; and Copies of audit reports on historical capital expense and operating expense.

In addition, the guidelines provide a number of issues that will be discussed during the pre-lodgement consultation period. This includes the process for verification of the estimated capital expense figure submitted at time of lodgement and the process for verification of future capital expense forecasts. Both of these are likely to require detailed review of the asset management plan and verification that the processes are being followed.


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1.7 Lessons Learned and Future Areas of Focus

The AER was only created on 1 July 2005 and while they have made transmission determinations, no electricity distribution determinations have been finalized or gas determinations yet undertaken. This short history means that there are relatively few lessons that can be learned from the AER’s experience. Some of the lessons from jurisdictional regulation were considered in a move to a single regulator, allowing adoption of a consistent approach across types of utilities.

The ERA is following (or intends to follow) a similar process to the AER for gas regulation, so this should ensure consistency. However, there is currently a difference of approach in electricity on time periods with the ERA initially having a relatively short regulatory control period of just 3 years, although this will subsequently move to 5 years. The ERA also has a single regulatory approach covering transmission and distribution, whereas typically, companies regulated by the AER are either transmission or distribution companies with different provisions in the NER.

The AER has stated that it will seek to implement a consistent regulatory approach for all networks where it is appropriate to do so and it is allowed and directed to under the legislation. However, the approach has deliberately been kept separate between electricity and gas and between distribution and transmission as there are different rules that need to be applied. This is particularly relevant in electricity where different forms of control are allowed between distribution and transmission businesses.

The consultation and general approach that both the AER and ERA have adopted appears consistent. All the review processes involve discussion before the initial submission and then detailed review that will involve consultants investigating key areas in more depth. There is then the opportunity for revisions after the draft decision is made before a final decision is then determined by the regulator.

Reviewing the recent consultant report and determinations by the regulator demonstrates the increasing importance of a robust asset management policy across all networks as part of the investment plan. However, while the asset management standards and procedures are a vital element of the investment plans, specific standards are not required. This is illustrated by the lack of explicit guidelines on asset management. A variety of approaches have been adopted and there is no indication that a particular approach is supported by the AER/ERA or by key industry groups such as the Energy Networks Association.

While there are few formal explicit requirements for asset management the approval of capital investment plans typically requires demonstration of good industry practice or prudent behavior by the network operator. This requirement implies that a solid asset management plan and strategy will be a pre-requisite to a revenue proposal being favorably reviewed by the technical experts in determining whether the asset replacement strategy, and therefore the investment plan, meets good industry practice.


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Future Focus

It is expected that the AER and ERA will continue to closely scrutinize investment plans, particularly as required investment increase with aging networks, near the end of their design life. This is likely to lead to increasing focus on asset management. However, it is also important to consider what changes to the market rules could occur, which could drive significant changes in the role of the regulator.

While the AER is responsible for economic regulation according to the market rules it is the Australian Energy Market Commission (AEMC) that is responsible for maintaining and updating these rules. In December 2008, the AEMC produced a Framework and Issues paper on the Total Factor Productivity (TFP) for the determination of prices and revenues potentially for all network companies. This review follows submission of a Rule Change proposal from the Victorian Minister for Energy and Resources to amend the NER to use TFP methodology as an alternative for electricity distribution determinations.

The TFP based approach would attempt to expose the network businesses to competitive like pressure by linking their prices and revenues to the productivity performance of the industry rather than an assessment of business specific costs. While the rules already permit benchmarking using TFP this assessment is considering whether more specifications on its application is needed in the rules and whether the inclusion of TFP would better meet the objectives of the NGL and NER.

Any move to a TFP approach creates a number of questions such as:

What industry definition should be used (i.e., what are comparable companies)?

How should the outputs and inputs for different energy sectors be classified? If a full TFP approach was chosen what should be the length of the regulatory

framework? Is a TFP based methodology consistent with a revenue form of control? Would a TFP based approach be suitable to determine the revenue path for

transmission companies (with more lumpy investment)? What would be the benefits and costs from having two forms of control?

Any decision will need to consider each of these issues. It is likely that, as in the UK, there will still be a need for a building block approach in calculating the initial RAB and capital expenditure and a technical review of this planned expenditure. However, it is unclear at this early stage in the review process what the impact could be (if any) on investment plans and required approach to asset management.

Appendix B: Germany

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2. Appendix B: Germany Regulatory Framework

In Germany, the Federal Network Agency (Bundesnetzagentur, or BNetzA), which was previously called the Regulatory Authority for Telecommunications and Post, was established on 1 January 1998 as a higher federal authority within the scope of business of the Federal Ministry of Economic and Technology (BMWi). As a result of the amended Energy Act 2005, it was assigned additional functions and renamed the Federal Network Agency for electricity, gas, telecommunications, post and railway in 2005. The Federal Network Agency's task is, through regulation of networks to promote competition in the telecoms, postal, railway and energy sector to ensure the provision of appropriate and adequate services, efficient use of network charges and to guarantee non-discriminatory third-party access to networks.

In the field of energy its role is to:

As far as possible, a secure, cost-efficient, consumer-friendly, efficient and environmentally compatible wired provision of electricity and gas to the general public; and

Working and undistorted competition in the provision of electricity and gas and ensures the efficient operation of energy supply networks on a long-term basis.

In Germany, there is a division of labor between the federal regulator (Bundesnetzagentur) and the regulators of the federal states18 (Landesregulierungsbehörden).

The regulation authority of the federal states are responsible for all network operators (electricity and gas) with less than 100,000 customers connected directly or indirectly to their grid; and

The federal regulator (i.e., the Bundesnetzagentur) is responsible for all network operators with more than 100,000 customers and with network areas located in more than one federal state.

Some of the federal states made use of the possibility to transfer the responsibility for regulation to the federal regulator. In this case the BNetzA is also responsible for the smaller network operators.

The regulatory authorities of the federal states have equivalent powers in relation to the utilities that they regulate. A working group has been set up comprising the federal regulator and the various authorities of the federal states. The purpose is to exchange information and to maintain a consistent regulatory approach for all utilities.

18 There are 16 federal states in Germany. 6 federal states have transferred the responsibility of regulation to the BNetzA.

Appendix B: Germany

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Market Context for Electricity

Germany is one of the largest energy markets in the European Union, with a gross annual electricity consumption of some 570 TWh, installed capacity in excess of 120 GW (of which around 23 GW can be considered as non-deployable), a peak demand of some 77.8 GW and a net annual production of approximately 597 TWh (2007). Germany also plays a major role in international power trading, both as an exporter, importer and for transits. As a result, Germany regularly exports and imports some 40 – 60 TWh annually.

Four players (RWE Power, E.ON Energy, Vattenfall Europe und EnBW) dominate German power production and the import and export of power. Together these four companies generate around 80% of the power produced in Germany.

Market Context for Gas

The German gas market is dominated by the following players:

Figure 14: Market Shares in the German Gas Market

48%

25%

12%

8%7%

BEB Erdgas and Erdöl Mobil Erdgas-Erdöl RWE DeaWintershall Holding Gaz de France-PEG

Source: European Energy Review

Germany has an annual net consumption of some 1,000 TWh, which is mainly covered by imports (Germany has an indigenous production of around 15%), including netting effects from gas exports. The German gas industry accounts for 20 million customers. According to CEDIGAZ, Germany has an estimated 713 Bcf of working natural gas storage capacity, the largest amount in the EU and the fourth largest in the world.

Appendix B: Germany

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There is no separation of network ownership from operation in Germany. Thus, all network businesses consist of Transmission System Operators (TSOs) - who both own and operate the transmission network they are responsible for; or Distribution System Operators (DSOs) - who both own and operate the distribution networks they are responsible for. As highlighted below the largest companies and some others are vertically integrated to a greater or lesser degree across the energy value chain (generation through to supply).

Electricity

The organizational structure of the network utilities in Germany is highly fragmented, with:

Four very large Transmission System Operators (TSOs) - E.ON, RWE, Vattenfall Europe, EnBW; and

More than 800 electricity regional and local/municipal utilities (i.e., distribution System Operators (DSOs).

The four largest companies directly and indirectly control more than 80% of both generation and supply and also own the four TSOs. Conversely, most of the several hundred municipal companies (“Stadtwerke”) are rather small and supply small towns or even villages, while the range of larger municipal and regional utilities is limited to some 20-30 companies.

The fact that the structure of the industry is diverse, made up of companies of various sizes, differences in ownership and network planning standards, with varying age of networks, largely reflects differences in the development between West and East Germany under the Cold War before the unification of Germany in 1990.

Table 15: Number of Electricity Transmission & Distribution System Operators in Germany

Reference Date

22.05.2006 21.06.2007 12.06.2008

Transmission System Operators 4 4 4

Distribution System Operators 876 877 855

Of which DSO with less than 100000 connected customers

799 799 779

Source: Bundesnetzagentur

Gas

Even following market liberalization, the number of companies in the gas sector has remained almost unchanged since the mid 1990s - in no other European country does such a vast amount of companies exists. Ten companies are active in domestic gas production and processing, and another 10 companies are active as importers. Some of these companies

Appendix B: Germany

2-4

operate high pressure/long distance pipeline networks and are responsible for the organization of a so-called market zone (also called market area), wherein gas transportation is internally coordinated among several network operators. They also coordinate transportation between different market areas. Moreover, around 40 companies operate regional transportation systems. Local distribution is done by approximately 700, often municipal and utility companies.

The gas market is dominated by E.ON – Ruhrgas AG, an internationally active gas company supplying 55% of the demand. Several transmission companies are responsible for long distance transport and for supplying the distribution companies. These are E.ON Ruhrgas, Wingas, Exxon Mobil, Shell, Verbundnetz Gas and RWE. There are a lot of ownership and/or controlling links between the approximately 700 utilities in the German market, which are dominantly held by E.ON Ruhrgas and RWE. Half of them have activities in electricity, gas and water. One third of these companies are pure gas distribution companies.

Figure 15: German Gas Market Structure

E.ON Ruhrgas, VNG, BEB, Wingas, RWE, Bayergas, GVS, Saar Ferngas, Erdgas Münster + Produzenten

10 domestic gas producers(15%)

Imports fromNL N RUS DK/GB

20% 26% 35% 4%

15 Transport system operators

app. 700 Local distributionsystem operators

Sales to national end users(households and small consumers/Industry/power plants)

Export

40 Regional system operators

Wintershall, ExxonMobil, RWE Dea, GdF-PEG

E.ON Ruhrgas, VNG, BEB, Wingas, RWE, Bayergas, GVS, Saar Ferngas, Erdgas Münster + Produzenten

10 domestic gas producers(15%)

Imports fromNL N RUS DK/GB

20% 26% 35% 4%

15 Transport system operators

app. 700 Local distributionsystem operators

Sales to national end users(households and small consumers/Industry/power plants)

Export

40 Regional system operators

Wintershall, ExxonMobil, RWE Dea, GdF-PEG

Most of the gas providers that supply end consumers are also part of integrated companies, which often provide customers with electricity, water and district heating. Only about 120 market players purely deal with gas. Independent new traders or suppliers who compete with incumbent suppliers, or existing companies that start to supply new customers beyond local boundaries, are still rare. Germany has numerous storage facilities that are operated by network/system operators or other companies.

Transmission networks are operated under different conditions. For example, some have access to underground storage facilities to balance their network; others are dependent on other networks or sources. Germany is located in the center of the European gas transmission system, which is reflected by numerous cross border points where gas enters and exits Germany. Imports primarily come from the North Sea (Norway, the Netherlands) and Russia.

Appendix B: Germany

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Transit functions are partially fulfilled by German transmission pipelines or extra transit pipelines (often owned and/or operated by different companies as so-called Transit Joint Ventures).

Table 16: Number of Gas Transmission & Distribution System Operators in Germany

Reference Date

22.05.2006 21.06.2007 12.06.2008

Transmission System Operators 22 22 20

Distribution System Operators 734 719 697

Of which DSO with less than 100 000 connected customers

708 694 668

Source: BundesNetzAgentur


The geographic area served and their respective shares of the four large TSOs are presented in the following figure. It can be seen that RWE and EON are the major players with dominant shares of 42.8% and 26.6% respectively.

Figure 16: Power Transmission Areas Served (Electricity)

Source: VDN/BDEW

The 850 electricity distribution network companies (i.e., DSOs) operating in Germany each have a highly dispersed structure and are of different sizes and also have different characteristics. In addition, the electricity and gas networks form part of multi-utility

42,80%

26,60%

11%

19,60%RWEEONEnBWVattenfall

Appendix B: Germany

2-6

companies for example, district heating and local transport. Some of the key features of the DSOs and for which there is variance between the different DSOs are as follows:

Geographically fragmented network (i.e., not all networks within a region may be owned by one DSO);

Population/customer density – from highly urban to highly rural; Geographical terrain – from flat to mountainous; Company size (e.g., reflecting for example the size of the municipality

served); Planning standards (vary between East/West Germany but also individual

DSOs); Network age (mainly East/West Germany differences); and Historic development (again differences between East / West Germany).

The following figure highlights the geographically fragmented infrastructure in Germany.

Figure 17: Distribution Network

Source: Verband der Netzbetreiber (VDN)/BDEW

Gas

There exist 12 mainly separate market areas (as of November 2008), currently reflecting the high and low caloric networks of the high-pressure and mostly supra-regional network owner/operators. A market zone goes from one or more entry points to several exit points and customers within a zone must be reachable from each entry point of this zone.

Appendix B: Germany

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Market areas are mostly spanned by the main gas transportation corridors of transportation and import companies and connected distribution networks. They provide a virtual trade point for gas transactions within the same zone.

Figure 18a gives an overview of the current market areas indicated by transmission networks; and

Figure 18b shows the fragmented German gas market structure considering transmission and distribution system operators.

Figure 18: Gas Market Structure by a) market areas; b) T&D system operators

Figure 18a Figure 18b

Source: www.gasnetzkarte.de

From Figure 18a it can be observed that the market areas are currently exclusively based upon property rights of the transmission system operators and may regionally overlap. Additionally, as high-pressure pipelines are often operated by a consortium of owners (companies) and network/system operators form a common market area, the latter are not designed to promote competition between different market areas or pipe-in-pipe rivalry between network/system operators within the same market zone. This is why gas trading is possible in only two market areas, moreover with rather limited liquidity.

It is expected that some market zones will be merged within the next couple of years and leave only a small number of zones which will exhibit differences based only on gas quality (high and low calorific gas) and (technical) capacity congestion. The following diagrams show the gas pipeline in Germany.

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2-8

Figure 19: Gas Pipelines in Germany

Source: EON Ruhrgas

2.1.3 Key Technical Statistics for German Network Utilities


The following figure provides an overview of the electricity transmission network:

Red – 380 kV lines; Green – 220 kV lines; and Purple line – HVDC (undersea cable).

Appendix B: Germany

2-9

Figure 20: Overview of Transmission Network (Electricity)

The following table shows the network length (km) split by voltage level:

Table 17: Network Length (Germany)

Low voltage (0,4 kV)

Middle Voltage (6 - 60 kV)

High Voltage (> 60 - < 220 kV)

Extra High Voltage (220 and 380 kV)

Total

Network length (km) 1,067,100 493,000 75,200 36,000 1,671,300

Source: www.vdn-berlin.de

The following table provides an overview of the key figures for the four transmission operators in Germany.

http://www.vdn-berlin.de/�

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2-10

Table 18: Key Figures of German Power Transmission Companies

Number of Customers

Area served

Units Distributed TWh (2007)

Line Length 380/220/110kV

Number of Substations

380/220/110kV

Number of Employees

EON 265 grid customers

138.780 km²

97.469 cir. 32,600 km cir. 1,050 cir. 1,500

RWE 76 grid customers 73,000km²

148.417 cir.11,300 km 180 substations cir.280

Vattenfall n/a 109,000km

²

53.759 - 9.500 km of 220kV/380kV overhead transmission lines, - 58km of 220kV/380kV cables.

73 50

EnBW

n/a 34,600 km²

51.159

380 kV: 1,970 km, 220 kV: 1,674 km

56 Switchgear systems & substations 8 transformers 380/220 kV 81 transformers 380/110 kV and 220/110 kV

cir.100

Source: Company reports

Gas Transmission and Distribution

The German gas network is the most complex in Europe. First, there are three network levels in addition to the two levels of “transmission” and “distribution”. As in most other countries, Germany has the additional level of “regional distribution”. Historically, a gas network evolved that is divided into a huge number of different networks characterized by different pressure conditions, operational conditions and different structure in terms of ownership and management as previously mentioned. Today, the total German gas network has a length of approximately:

375,000 km, 61,000 km thereof are classified transmission pipelines; and 314,000 km distribution pipelines.

Theoretically, the different network levels can be distinguished by different pipe diameters and pressure ranges. The official classification of a high-pressure transmission network in Germany starts with one bar, although practice rather defines it by dimensions ranging from 60 to more than 80 bars. This shows that network levels are not precisely defined in Germany, (e.g., regional distribution companies are also partly active on the long distance transmission levels and a distribution networks can include a regional transmission part, etc.).

The table presented over the next two pages highlights some key figures for selected gas transmission and distribution companies.

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2-11

Table 19: Key Figures of German Gas Transmission & Distribution Companies data from 2007 RWE EON Wingas Exxon Mobil VNG

RWE Dea RWE Energy npower Group Eon Ruhrgas Thüga EMPG EMGMG

international gas field exploration and production

energy supply for Germany and Continental Europe

UK Germany and abroad

Germany distribution

Germany Germany Germany

Storage capacity in bn m3

1.9 4.22) – 6.1 5,280 6.6 3 2.3

Pipelines in km (total)3)

– 95,2005) – 116.405 7040

Gas transport grid 7,7005)

– Germany 4,1005) 11.611 1953 3400

– Abroad 3,6005)

Gas distribution grid

87,5005)

– Germany 30,7005) 220

– Gas pressure regulation and metering station

2.85

– Connection points: end users and redistributors

783

– Abroad 56,8005)

Appendix B: Germany

2-12

Customers – 7,600,000 2,700,000 10,300,000 - 25% export, - 10% German industry - 42% German transportation companies, - 23 % distributors, of total sales volume

3,900,000 60 (European-

wide)

- 69 Distribution companies - 24 trading companies - 7 local municipal distributors and end consumers

31 % to industrial customers, 58 % to regional/local distributors 11 % export, of total sales volume

Sales volume in bn kWh

20 259 56 335 712.8 177.6 254.3 140.4 165.2 (Germany,

abroad) Production in bn m3

n/a n/a n/a n/a 795 (internationall

y)

n/a n/a 12 0

connected networks

n/a n/a n/a n/a n/a n/a n/a n/a n/a 130

Table Notes:

1) Excluding RWE Supply & Trading.

2) Including potential extensions.

3) Share in German grid: Transmission System Operator 11%, Distribution System Operator 10%.

4) Including oil revenue.

5) Excluding connection lines.

Appendix B: Germany

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Electricity and Gas Distribution

Due to the vast amount of distribution companies in Germany, providing a breakdown of the number of customers per utility proved to be extremely difficult. We have however provided an overview based on information from the German regulator website and also the number of companies that applied for the simplified regulatory review procedure. The simplified procedure is applied to utilities with less than 30.000 connected customers (electricity) and less than 15.000 connected customers for gas. Approximately 650 electricity utilities and approximately 540 gas utilities applied for the simplified incentive regulation scheme, so we can assume based on the information that the number of utilities and the number of connected customers are as follows:

Table 20: Number of Customers per Utility in Germany (Electricity)

Number of Customers Number of distribution system operators

More than 100.000 connected customers 76 Less than 100.000 connected customers 129 Less than 30.000 connected customers Approx 650 Total distribution system operators 855

Table 21: Number of Customers per Utility in Germany (Gas)

Number of Customers Number of distribution system operators More than 100.000 connected customers 29 Less than 100.000 connected customers 128 Less than 30.000 connected customers Approx 540 Total distribution system operators 697


The following figure provides an overview of the ownership structure of the distribution networks for electricity and gas. The ownership of these companies varies; some are publicly owned, privately owned or mixed. Some companies have subsidiaries in all levels of the value chain and or shares in other utilities.

Appendix B: Germany

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Figure 21: Ownership Structure (Distribution for Electricity and Gas)

480

128

Local enterprises held byseveral municipalities

Local enterprises completelyheld by the muncipality

55

219

49

Privat shareless than 25 %

Privat sharebetween 25 %and 50 %

Privat sharehigher than 50 %

Local enterprises held by several municipalities orutilities containing private shares

28

480

128

Local enterprises held byseveral municipalities

Local enterprises completelyheld by the muncipality

55

219

49

Privat shareless than 25 %

Privat sharebetween 25 %and 50 %

Privat sharehigher than 50 %

Local enterprises held by several municipalities orutilities containing private shares

28

Source: VKU

The German energy markets are characterized by a significant level of market concentration and a dominant position of transmission companies with strong equity holding in many distribution companies. According to the European Commission’s electricity and gas sector inquiry from 2006, both European wholesale energy markets exhibit, among others:

Market concentration to the same extent as before market liberalization, as incumbent companies still control great parts of power generation and gas import and production;

Vertical integration of companies to high extent; and Lack of foreign competition in the field of gas and electricity supply.

The EU Commission’s findings were confirmed by the German regulator’s 2008 monitoring report on German energy markets. Against this background, the federal court recently prohibited E.ON to acquire stakes of a smaller electricity distribution company.


The Bundesnetzagentur currently approves grid fees (ex-ante) of the regulated utilities for both transmission and distribution and electricity and gas on a yearly basis based on a cost plus regulation approach.

Appendix B: Germany

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However, from 1 January 2009 all transmission and distribution gas and electricity network businesses will be regulated under an incentive regulation regime. These utilities will be subject to a revenue cap19 regulation based on TOTEX20 regulation.

Due the large number of utilities in Germany the duration of the first price control under incentive regulation for electricity and gas are different; so that for the future there will be a “stagger” between regulatory reviews of gas and electricity network utilities.

Electricity transmission and distribution – the upcoming price control period is 2009 to 2013 (5-year period). Thereafter 5 years; and

Gas transmission and distribution – 2009 to 2012 (4-year period). Thereafter 5 years.

The purpose of staggering the price control periods is to enable the regulator to conduct its reviews for the subsequent periods effectively.

For this report we will refer to the mechanisms under the incentive regulation scheme related to investment planning and asset management where applicable. We highlight the appropriate differences between transmission and distribution and electricity and gas, otherwise the methodology and processes are the same.

This section is set out as follows:

Insight to the general regulatory process applied for electricity and gas transmission and distribution system owners. (2.2.1);

Discussion of the investment budget mechanism and how this is dealt with within the regulatory regime for electricity and gas transmission and distribution system owners. (2.2.2);

Treatment of asset replacement expenditure for electricity and gas transmission and distribution system owners. (2.2.3);

Quantity Adjustment Term applicable for electricity and gas distribution (2.2.4); and

Investment Supplement applicable for electricity and gas distribution (2.2.5).

The last two points (Quantity Adjustment Factor and the Investment Supplement) are two additional mechanisms applied to electricity and gas distribution only. More details regarding

19 Revenue cap in its simplest form is putting a cap on the revenue that a regulated company can earn over the regulatory period. Under this, revenues are set in advance usually for a certain period e.g., five years allowing the regulated utility to benefit from any cost savings made during that period, but recalculated at regular intervals in order to bring them back into line with underlying costs. The “cap” refers to the upper limit that is placed on revenue that a utility can receive from it network charges, hence the term “revenue cap”. 20 TOTEX = CAPEX + OPEX. CAPEX is made of 4 components of existing assets. These are regulatory return on equity, regulatory return of debt, regulatory depreciation and trade tax.

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these mechanisms are given in their respective sections including why these mechanisms are not valid for the electricity and gas TSOs.

It is important to highlight and emphasize that the exact incentive regulation regime, which will apply for 2009-2013, is not yet in place at the time of writing this report. However, this report will nevertheless include all relevant undergoing discussions between the industry and the regulator related to the treatment of the investment budget and asset replacement expenditure.

2.2.1 General Regulatory Process

To give an idea of the process leading up to the incentive regulation regime to be implemented from January 2009, the regulator first published an initial proposal for design of incentive regulation on 30 June 2006. This initiated the consultation process whereby industry and other respective bodies could comment and give feedback on the proposals. In November 2007, the Incentive Regulation Ordinance came into force. The ordinance is a legally binding document and contains the rules of the new regulatory regime. In addition, other documents interrelated to the network pricing came/stayed into effect. The Network Pricing Ordinances for gas and electricity contains the accounting rules for the determination of the cost base for the former cost-based regulation and will be still be used under the new incentive regulation scheme.

The Ordinance for Incentive Regulation contains the detailed rules and methodology for calculating the allowed revenues of the regulated network utilities for both electricity and gas and for both transmission and distribution networks. The methodology for transmission and distribution are similar as the same revenue cap formula is used for both the transmission and for distribution. There are some exceptions to the methodology. For example, for transmission (electricity and gas) network utilities; the quantity adjustment factor does not apply and the so-called permanently non-controllable cost term may comprise additional components. In addition, Paragraph 23 of the Incentive Regulation Ordinance includes a mechanism called the investment budget, which is aimed primarily for electricity and gas transmission system owners, although it can be applied to the electricity and gas distribution utilities as well. These terms are explained in more detail in the following sub-sections.

The general revenue cap formula for electricity and gas transmission and distribution is as follows:

Appendix B: Germany

2-17

( )[ ] ttttt

btvnbtdnbt SQEFPFVPIVPI

KAVKAKAEO ++⎟⎟⎠

⎞⎜⎜⎝

⎛−⋅⋅−++= *1

00,0,,

EOt allowed ‘capped’ revenue, year t

KAdnb,t permanently non-controllable costs, year t

KAvnb,0 temporarily non-controllable costs (“efficient costs”,) base year

Vt individual reduction factor for inefficient costs in year t

KAb,0 inefficient costs (controllable), base year

VPIt Consumer Price Index (CPI) for year t-2

VPI0 Consumer Price Index (CPI) base year

PFt General Productivity factor year t

EFt Quantity adjustment term, year “t” (not applicable for transmission of gas and electricity)

Qt Quality adjustment term, year “t”

St Regulatory account, year “t” (from second price control period)

The Ordinance on Incentive Regulation indicates that 2006 cost data of the regulated companies is used in establishing the opening value for year 2009, the first year of the price control period. The individual electricity/gas TSO/DSOs’ total costs are divided between:

Non-controllable costs (KAdnb,t in the cap formula) ; and Controllable costs (KAvnb,0 + KAb,0 in the cap formula).

The non-controllable cost items are explicitly defined in the Ordinance on Incentive Regulation and include items such as fees, costs associated with a legal obligation (under the Renewable Energy Act 2004) to connect power plants generated by renewable energy to its network, use of network charges paid by the distributors, operating taxes, concession levies, construction subsidies and investment budget.

The individual efficiency result is used to determine the percentage of controllable costs that are considered inefficient. The efficiency result is multiplied with the total controllable cost to calculate the efficient cost of the network operator (e.g., assuming the controllable cost = 100 and the efficiency result = 80% efficiency the efficient cost of the network operator KAvnb,0 = 80 while the inefficient cost of the network operator KAb,0 = 20). The inefficient costs need to be reduced during the regulatory period according to the reduction factor for

Appendix B: Germany

2-18

inefficient costs (Vt in the cap formula). Vt is set so that these costs are reduced to zero over a 10-year period at the beginning. Please note that due to the TOTEX approach of the regulator the controllable costs comprise both capital expense and operating expense, meaning that investment decisions in the past are challenged by the efficiency comparison and could be considered inefficient ex-post.

All controllable costs are adjusted for:

Inflation (VPIt / VPI0 in the cap formula). The inflation is calculated with a 2 year lack using the consumer price index (e.g., inflation factor used for 2010 is VPI2008 / VPI2006 and for 2011 is VPI2009 / VPI2006);

A general productivity improvement target (PFt in the cap formula), which the ordinance sets as 1.25% p.a. in the first price control period and 1.50% for the second regulatory period; and

The quantity adjustment term (not applicable for transmission of gas and electricity).

Investment plans of the electricity/gas TSO or DSO are only reviewed by the regulator to the extent when they apply for a specific investment budget. The following section describes the investment budget mechanism in more detail. The procedure for the application and approval process is identical for all the utilities.

2.2.2 Investment Budgets for Transmission and Distribution

A component that falls under non-controllable costs is a mechanism called the “investment budget”. The investment budget enables the allowed revenue to be adjusted (ex-ante) for the capital costs (capital expense allowance) of certain types of investments. This means that the approved investment will not be part of the general regulatory asset base for the approval period21 and therefore not be part of the cost considered in the efficiency benchmarking. Instead, the capital cost is passed through to the network user as non-controllable costs. The capital cost components include:

Regulatory return on equity of the project assets; Regulatory return on debt of the project assets; Regulatory depreciation of the project assets; and Project specific trade tax.

The investment budget is mainly applied to electricity and gas TSOs; however, in Paragraph 23, Section 6 of the Incentive Regulation Ordinance, in special circumstances the electricity and gas distribution network companies can also apply for the investment budget. For example, if the purpose of an investment project meets the criteria as specified in the

21 The length of the approval period is not equal to one price control period but could be longer. At the time of writing this report the length of the approval period has not been confirmed by the regulator but is can be assumed that it will be for two price control periods.

Appendix B: Germany

2-19

ordinance then the same process would also apply for electricity and gas distribution. The type of investments that are considered as part of the investment budget include investments required for the expansion/extension or reinforcement of the transmission and distribution network, connection of new generators or the integration with national with international networks. The criteria of investment budget projects as specified in the ordinance consist of:

New lines to connect off-shore wind farms; New underground cables; Necessary restructuring measures to ensure and maintain the technical

security of the network; Construction of cross-boarder capacities; Integration of generation units subject to the Renewables and CHP Act; and Connection of new generation units.

This implies that any application and approval for the investment budget projects must fall under the above listed categories.

A list published on the regulator’s website showing the utilities who have applied for the investment budget in 2008 includes more than 15 distribution companies. In total, applications for electricity networks added up to 8.6 bn Euros, of which 6.2 bn Euros was for transmission network investment. The applications for gas networks added up to 850 m Euros for 300 projects altogether, of which distribution networks account for around 150.22 From this list an indication of the project type (e.g., expansion project) is also given. The list does not indicate whether the investment was approved or not.

One of the main reasons why the investment budget is mainly for transmission is that the investment projects for transmission are usually of greater value and size than that for distribution. The criteria specified in the incentive regulation ordinance for the application of the investment budget are for projects which are related to network extension and connection to the transmission grid of power plants generated by renewable energy, which in most cases are related to transmission.

Application and Assessment

There is a formal procedure to apply for the investment budget. The respective network business is required to apply for the investment budget at least 6 months (i.e., by 30 June) before the start of the calendar year in which the cost of the investment will be shown, either as a full amount or partially in the accounts of the TSO. One application can be requested to cover an investment taking place over several years and price control periods.

The reason for one application covering several years is to take into consideration that a project of a large scale may take more than 1 year to be fully operational. In terms of how this

22 The numbers are provided by the head of the BNetzA Matthias Kurth ,Anreizregulierung und Investitionen, emw no. 4, 2008, pp. 6-11

Appendix B: Germany

2-20

fits with the 5-year regulatory cycle, this means that the approval of an investment budget is not bound to the price control period in which the investment takes place. If the application covers more than 1 year, the approved capital expenditure allowance (return on equity, return on debt, regulatory depreciation and trade tax of the project) will not be part of the general Regulatory Asset Base (RAB) at the time the regulator conducts the revenue resetting for the subsequent price control period, since its capital cost is considered as non-controllable (i.e., covering two or more price control periods). The project capital expense allowance would be an item under the permanently non-controllable costs term of the price control formula, and correspondingly, be remunerated by this mechanism.

As specified in the Incentive Regulation Ordinance there is a 2 year time lag before the investment budget is considered as part of the permanently non-controllable costs and hence, before any capital return is received. For example, the investment budget approved in 2009 will be considered in 2011 for the first time. The underlying assumption of the 2 year lag is that the initial calculations for determining the revenue allowances are based on historical data (i.e., 2006 data was used for setting the revenue cap for 2009). The regulator wanted to keep a consistent approach using historic cost with a 2 year time lag so that no corrections/adjustments of forecast errors are needed in the price control formula.

Current discussions between the regulator and industry in regards to the 2 year lag are underway, especially as the industry is opposing this 2 year lag and would prefer that the investment budget could be added to its permanently non-controllable costs without any time lag at all. The allowed revenue will be adjusted upwards to take the approved investment budget into consideration. Recent press releases from the regulator regarding this issue is that the regulator is considering an adjustment to the Incentive Regulation Ordinance to allow for the time value of money (Barwertausgleich) as a result of the 2 year time lag. However, this is still under discussion and has not yet been officially confirmed.

The capital allowance of investment budget for a project has to be approved for a certain period of time. At present there are discussions underway on whether the capital allowance should be included for the duration of the asset life or a fixed period of time (i.e., 10 years). After this period the assets will be transferred to the general regulatory asset base (RAB) at their residual value. At the moment it is most likely that the capital allowance is approved for two price control periods (meaning the period in which it is applied for the first time plus the following price control period). The implications for the duration of the investment budget have an impact on the regulatory asset base (RAB) at the time of the price control review for the next regulatory period and the amount of cost that is considered in the benchmarking exercise.

In two separate documents (one for electricity and one for gas) on the regulator’s website, guidelines for the application and approval procedures of the investment budget for electricity

Appendix B: Germany

2-21

and gas are published23. The application form is an Excel file with 6 worksheets which can be downloaded from the regulator’s website. For each individual project the transmission and distribution system owners must complete a separate form. There is a separate file for gas and electricity. The main information in this form consists of:

Name of the investment project; Purpose of the investment; Acquisition cost of the investment project; Asset life of asset; Planned commissioning date of the project; and Indication of the criteria that the investment comes under from the criteria

specified in the incentive regulation ordinance Paragraph 23.

Once the application has been received the regulator makes an assessment before approving the capital expenditure allowance for new investments. At present a lot of discussions between the industry and the regulator on the investment budget are taking place, especially whether there could be ex-post investment approvals for the years 2007 and 2008 as the regulation as such starts in 2009. This has been allowed by the regulator and is therefore remunerated by this mechanism by adjusting the non-controllable cost.

Use of Reference Network by Regulator to check investment need

The regulator can check the investment need upon receiving the application with the aid of a reference network model as stipulated in Paragraph 23, Section 4 of the Incentive Regulation Ordinance. The use of reference network model is to attempt to mimic investment on expanding and refurbishing networks and to use this to assess the application of the proposed investment. The regulator may use reference network models to check the economic usefulness of the planned investment volumes.

The purpose of the reference network model is to support the regulator in analyzing the proposed investment against an optimal, technically feasible network structure.

As an addition to the investment budget application, technical information is also required from the TSO.24 The technical information consists of the details on the area of supply (e.g., all feed in and feed out points, the number of customers, details on the neighboring network) and information on the network topology (e.g., switching stations, transformers, network length). The technical information is used to determine the reference network since the model is based on the current network in Germany (brown field approach).

23 Leitfaden zu Inhalt und Struktur von Anträgen auf Genehmigung von Investitionsbudgets nach Paragraph 23 Abs. 3 ARegV im Bereich Elektrizität & Gas. 24 Technische Daten zur Durchführung der Referenznetzanalyse für Übertragungsnetzbetreiber nach Paragraph 23 ARegV.

Appendix B: Germany

2-22

The regulator checks the applications for investment budget and may disallow ex-ante (i.e., not approve) part of the investments if they feel that the planned investments, in terms of engineering configuration and construction work procurement, are not economically sound. In addition, the regulator can re-call the approved investment budget if the investment was not carried out as agreed.

2.2.3 Asset Replacement Expenditure (REPEX)

An important point here is that investments for the replacement of assets are not considered part of the investment budget. Capital returns resulting from replacement expenditure is not explicitly remunerated in the respective price control period. Asset replacement expenditure is in the decision of the regulated system operators (electricity and gas transmission and distribution). The regulator does not assess and determine the volume of replacement but can ask for a report on investment behavior according to Paragraph 21 of the Incentive Regulation Ordinance. For example, during the price control period (2009-2013 electricity, 2009-2012 gas) capital spent on REPEX is not adjusted or considered in the allowed revenues. The REPEX will form part of the regulatory asset base (RAB) when the regulator conducts the revenue resetting for the review for the next (subsequent) price control period (e.g., 2014-2018 electricity, 2013-2017 gas). When the review takes place (e.g., 2011 for electricity, 2010 for gas) the regulator collects information from the utilities regarding their assets (35 asset groups for electricity and 44 asset groups for gas). This information consists of residual values on each individual asset and also information on any disposals and/or additions of the respective asset.

The reason why any REPEX made during a price control period is not considered in the allowed revenues is because the regulatory scheme is based on existing values of assets and not on the planned values of assets. When calculating the initial revenue the depreciation of the existing assets is already considered and included in the revenue cap for the duration of the price control. It would be in the interest of the electricity or gas TSO/DSO to replace the respective asset at the end of the asset’s respective useful life. The DSO/TSO does not get explicit funding (i.e., it is not passed through to the network charges during the price control period) as REPEX is specifically related to the replacement of the existing assets. It is the responsibility of the respective TSO/DSO to replace assets in their network infrastructure.

Share of Replacement Expenditure in Investment Budgets

The regulator assumes and recognizes that part of the applications for investment budgets contains a replacement element (e.g., upgrading of a line). Therefore, according to the investment budget criteria, the replacement component and the proposed new investment need to be distinguished in order to avoid reallocation of replacement asset as extension/expansion expenditure, which would be recognized under the investment budget and thus, remunerated by adjusting the allowed revenues by the non-controllable cost component.

Appendix B: Germany

2-23

At present, the regulator is considering an approach to separate the share of replacement expenditure from the investment budget as follows25:

The regulator assesses the basic replacement needs of the individual electricity and gas TSO or DSO by calculating the average actual investments made in 2002-2006 and assuming that 60% of this is replacement. Only the amount of the investment budget over 60% of the average investment will be recognized as investment budget.

To illustrate a simple example follows:

A TSO in the period 2002-2006 made investments of 1000€; Average of 1000€ over the 5 year period = 200€; and 60% of 200€ = 120€.

Therefore, 120€ would be the minimum amount for asset replacement. This means that in the case of an investment budget application of 500€ only 380€ would be recognized as an approved investment that falls under the investment budget rules.

However, this discussion is currently underway and final proposals from the regulator have not yet been confirmed.

2.2.4 Quantity Adjustment Term (EFt) for Distribution Electricity and Gas

In the Incentive Regulation Ordinance Paragraph 10, a mechanism called the quantity adjustment term allows an adjustment to the allowed revenue of electricity and gas DSOs. This term is used when changes occur to the original network configuration, such as the distribution area served and the connection of new network customers, which affect the overall costs of the distribution system operator.

The ordinance specifies the following criteria that have to be met in order to allow the electricity and gas distribution networks owners to apply for the quantity adjustment term. The table provides an overview of the criteria for electricity and gas respectively:

25 Please note that this is currently under discussion and this approach has not been confirmed or established in the respective ordinances.

Appendix B: Germany

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Table 22 Criteria that Need to be Met for Quality Adjustment Criteria Electricity Distribution Gas Distribution

Expansion of the network system (size of the area supplied/of the geographical area)

Number of connection points for electricity distribution network per network level

Load per electricity network level

Expansion of the network system (size of the area supplied/of the geographical area)

Number of exit points for gas distribution network

Overall load of the gas network

If the investment cost required for the above listed points is more than 0.5% of the difference of the total cost after deducting non-controllable costs then the respective electricity and gas DSOs can make a formal application to the regulator to have this considered in its allowed revenues. The quantity adjustment term is not related to investment planning or asset replacement but is related to increase of costs due to new connections/higher load during the price control period. It creates a relation between load growth and cost. This enables the electricity or gas DSO to transfer part of these costs to the grid charges during the actual price control period.

A formal application must be made to the regulator by 30 June of the preceding calendar year in order for these changes to be considered and adjusted (increase) to the revenue cap. The deadline for the first applications of the quantity adjustment term is 30 June 2009 for adjustment to the revenue cap to be considered in 2010. The quantity adjustment term as stipulated in the ordinance can only be used during the price control period (this means that this is invalid in the first year of the regulatory period). The guidelines for the application will be developed by the regulator at the start of 2009. We assume that the approval of the application of a quantity adjustment term will rely on historic data (e.g., load growth of the previous year). The electricity and gas DSOs need to justify an increase in total cost, which will be assessed by the regulator.

This mechanism is not applicable for electricity and gas TSOs. The application of a quantity adjustment term for electricity and gas transmission was not considered adequate by the regulator as in the area of transmission there is no continuous adaptation of the assets to small changes in the transported energy. The quantity adjustment term addresses the issue that for the distribution area there is no link between load growth/increasing number of connections and the resulting cost increase. In this area, changes in demand may lead to high investment needs, which might be covered under investment budgets.

Appendix B: Germany

2-25

2.2.5 Investment Supplement for Distribution Gas and Electricity

Paragraph 25 of the Incentive Regulation Ordinance allows electricity and gas distribution system operators to apply for an investment supplement. The investment supplement is a one-off allowance (it is only valid for the first incentive regulation period 2009-2013 electricity and 2009-2012 gas) set at a maximum of 1% of the annual capital cost of the electricity or gas DSO. The annual capital cost consists of:

Return on equity; Return on debt; Regulatory depreciation; and Regulatory trade tax.

The one-off allowance is considered as a permanently non-controllable cost item and aims at incentivizing the electricity and gas distribution system operators to adequate investment. This mechanism serves to avoid under-investment in the gas and electricity distribution infrastructure during the beginning phase of the incentive regulation regime.

The investment supplement is not applicable for electricity and gas transmission as the investment budget should cover extension/expansion investment for the electricity and gas TSOs. In addition, due to the vast amount of electricity and gas DSOs, this one-off allowance is automatically applicable for all DSOs (who applied for it) and enables the regulator to automatically approve this instead of having to assess each individual investment for each individual DSO.

For example, a DSO applies for the investment supplement of 1% of its annual capital costs, the regulator will then make an assessment (ex-post) to see whether there is a deviation to this amount. For example, if the distribution company actually used 0.5%, then the difference to the original investment supplement will be deducted in the next regulatory period (2014-2018) from the permanently controllable cost (which is a pass through cost). If the actual investment cost is greater than the 1% (e.g., 1.5%), then the extra 0.5% will not be considered at all. The DSOs had to apply by 31 March 2008 for the investment supplement to be considered in their allowed revenues starting in 2009.

Due to the vast amount of electricity and gas DSOs this one-off allowance is automatically applicable for all DSOs (who applied for it) and enables the regulator not to have to make an individual assessment of each investment of each electricity and gas DSO. The investment supplement will be automatically recognized for all electricity and gas DSOs, although the regulator may conduct random checks.

The investment supplement is not applicable for electricity and gas transmission as the investment budget should cover extension/expansion investment for the electricity and gas TSOs.

Appendix B: Germany

2-26


This section describes the information and reporting requirements applicable to the utilities (gas and electricity, transmission and distribution) that the regulator requests.

Some data requests are mainly a result of obligations set in legislation. For example, the regulator has to produce a report on a certain topic such as a report by 2013 on the assessment of whether the incentive regulation regime has impacted negatively on the investment behavior of the utilities.

In most cases, in order for the regulator to gather information about the utilitiesm, data collection templates are issued. In the following sub-sections, an overview of the data collection and reporting requirements is given.

2.3.1 Formal Data Collection Requirements – Price Control Reviews

In reference to the process to determine the initial revenues for each utility, cost data is collected from each utility in order for the regulator to conduct its assessments. The Incentive Regulation Ordinance states that 2006 cost data is used as the base year to calculate the initial revenue basis for 2009, the first year of the first (incentive regulation) regulatory period. Correspondingly, 2011 cost data will be used for the determination of the initial revenue for 2014 for electricity (the first year of the second regulatory period). For gas, 2010 and 2015 cost data will be used for the subsequent regulatory periods. The following diagram presents an overview of the time schedule and the relevant year for which data is collected to determine the initial revenues of each price control period.

Figure 22: Time Schedule for Data Collection for Regulatory Purposes

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

1st regulatory period 2nd regulatory period 3rd period

2011 Cost Data forElectricity to:

2010 Cost Datafor Gas to:

Determination of initialrevenue 2nd regulatoryperiod

- Determination of efficiencyfactor for 2nd regulatoryperiod



Determination of initialrevenue 3rd regulatoryperiod

- Determination of efficiencyfactor for 3rd regulatoryperiod

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

1st regulatory period 2nd regulatory period 3rd period



Determination of initialrevenue 2nd regulatoryperiod

- Determination of efficiencyfactor for 2nd regulatoryperiod



Determination of initialrevenue 3rd regulatoryperiod

- Determination of efficiencyfactor for 3rd regulatoryperiod

The data collection process started in 2007 for the upcoming regulatory period 2009-2013. The lead time was required due to the large number of gas and electricity utilities in Germany. It was an ongoing iterative process involving many consultation rounds between the industry and the regulator.

Appendix B: Germany

2-27

A data collection template (Betriebsabrechnungsbogen) specific for price control purposes was issued. The information that was collected included financial data of the utilities such as operating expenses, data on the assets such as year of commissioning, cost of the asset, asset age, remaining useful life, and depreciation. This is intended to give the regulator an insight into the utilities’ technical and financial information, as well as operational policy and strategy.

The template is in Excel format and consists of 10 worksheets. The following diagram shows an excerpt from this template for illustration on the type of information that is collected:

Table 23: Excerpt from the Data Collection Template (Betriebsabrechnungsbogen)

I. Erfassung der Kostenarten Cost Types 1. Aufwandsgleiche Kosten Cash Outlay Costs 1.1. Materialkosten Material Costs 1.1.1. Aufwendungen für Roh-, Hilfs- und

Betriebsstoffe Cost of raw materials & consumables

1.1.1.1. Aufwendungen für die Beschaffung von Verlustenergie

Cost for procurement of network losses

1.1.1.2. Aufwendungen für Stromeinspeisung durch Betreiber dezentraler Erzeugungsanlagen

Cost for electricity supply through operators of decentralized generation plants

1.1.1.2.a. davon nach EEG ~ renewable energy 1.1.1.2.b. davon nach KWK-G ~ combined heat and power 1.1.1.2.c. davon nach § 18 StromNEV ~ Article 18 of Network Charge

Ordinance 1.1.1.3. Betriebsverbrauch Cost for operating (own) consumption 1.1.1.4. Aufwendungen für Differenz-Bilanzkreise

bzw. Aufwendungen für den Ausgleich von Abweichungen bei Standardlastprofilen

Cost for balancing group or for balancing deviations in standard load profiles

1.1.1.5. Sonstiges Miscellaneous 1.1.2. Aufwendungen für bezogene Leistungen Cost of purchased services 1.1.2.1. Aufwendungen an vorgelagerten

Netzbetreiber Network charges for usage of higher voltage levels

1.1.2.2. Aufwendungen für überlassene Netzinfrastruktur

Expenditure on network infrastructure from third parties

1.1.2.3. Aufwendungen für durch Dritte erbrachte Betriebsführung

Third party expenditure for management services

1.1.2.4. Aufwendungen für durch Dritte erbrachte Wartungs- und Instandhaltungsleistungen

Third party expenses for maintenance

1.1.2.5. Sonstiges Miscellaneous 1.2. Personalkosten Labor Costs 1.2.1. Löhne und Gehälter Wages and salaries 1.2.2. Soziale Abgaben und Aufwendungen für

Altersversorgung und für Unterstützung Social contributions, pension costs and benefits

1.2.2.1 davon für Altersversorgung ~ pension costs 1.2.2.2 davon soziale Abgaben und sonstige

Aufwendungen ~ social contributions and other costs

Appendix B: Germany

2-28

1.3. Fremdkapitalzinsen Interest on Borrowed Capital 1.3.1. davon gegenüber verbundenen

Unternehmen ~ affiliated companies

1.3.2. davon gegenüber Unternehmen, mit denen ein Beteiligungsverhältnis besteht

~ companies in which investments are held

1.3.3. davon gegenüber Kreditinstituten ~ loans from credit institutions 1.3.4. Sonstiges Miscellaneous 1.4. Ansetzbare betriebliche Steuern (außer

Gewerbesteuer, Körperschaftsteuer, Einkommensteuer und Solidaritätszuschlag)

Operating taxes (not incl. trade tax, corporation tax, income tax, solidarity tax)

1.5. Sonstige betriebliche Kosten Other Operational Costs 1.5.1. davon Konzessionsabgaben concession levy 1.5.2. davon Mieten, sonstige Pachtzinsen,

sonstige Leasingraten, Gebühren und Beiträge

~ rent, other rental costs, other leasing rates, fees and contributions

1.5.3. davon Versicherungen ~ insurance 1.5.4. davon Bürobedarf, Drucksachen und

Zeitschriften ~ office supplies, printing costs, journals

1.5.5. davon Postkosten, Frachtkosten und ähnliche Kosten

~ postal costs, freight and other similar costs

1.5.6. davon Rechts- und Beratungskosten ~ legal and consulting costs 1.5.7. davon Sponsoring, Werbung, Spenden ~ sponsorship, advertising, donations 1.5.8. davon Reisekosten und Auslösungen ~ travel costs & accomodation

allowance 1.5.9. davon Bewirtung und Geschenke ~ hospitality & gifts 1.5.10. davon Wartung und Instandsetzung ~ maintenance & repairs 1.5.11. davon Einzelwertberichtigungen und

Abschreibungen auf Forderungen ~ allowance for bad debts

1.5.12. Sonstiges Miscellaneous 2. Abschreibungen Depreciation 2.1. Kalk. Abschreibungen

Sachanlagevermögen Depreciation of tangible fixed assets

2.1.1. Kalk. Abschreibungen Kabel depreciation of underground cables 2.1.1.1. Kalk. Abschreibungen Kabel 220 kV depreciation of underground cables 220

kV 2.1.1.2. Kalk. Abschreibungen Kabel 110 kV depreciation of underground cables 110

kV 2.1.1.3. Kalk. Abschreibungen Kabel

Mittelspannungsnetz depreciation of medium voltage network underground cables

2.1.1.4. Kalk. Abschreibungen Kabel 1 kV depreciation of underground cables 1kV 2.1.1.5. Kalk. Abschreibungen Kabel

Abnehmeranschlüsse depreciation of consumer connection underground cables

Appendix B: Germany

2-29


There is no explicit regulatory guidance regarding the specific preparation of asset management. Primary and secondary legislation do not contain any technical rules on (physical, organizational) asset management, nor do they entitle the regulator to provide these rules. During the consultation process between the regulator and industry regarding incentive regulation the topic of asset management was discussed but was not established in the legislation (e.g., Energy Act or in the respective ordinances). The industry opposed this and viewed this as micro management from the regulator.26

The utilities are free to decide themselves how to operate their technical assets, so long as they meet the obligations in the Energy Act on maintaining a stable and reliable network, and secure security of supply.

Technical Codes and Voluntary Initiatives

In some cases the utilities have agreed on common guidelines. However, these agreements, which partly build on voluntary initiatives, mainly expand and specify existing legal provisions without committing the electricity and gas TSOs and DSOs to concrete rules for network operation. Some of them represent commonly recognized technical standards.

The technical rules and codes are not legally binding but it is common practice that the electricity and gas TSOs and DSOs adhere to them. The following provides a summary of these codes that are currently in place.

The Transmission Code (amended 2007) represents a set of rules, which was developed and introduced by the four German TSOs without any formal industry consultation and/or approval by the regulator. The transmission code is a voluntary agreement but it is built on the requirements as set out in the Energy Act to operate a safe and secure network. Amongst others, the Transmission Code sets out the main principles in regards to the following points:

Disturbance management (e.g., frequency deviations, load balancing, system services), considering containment;

Measures, TSO’s responsibilities, procedural course of actions, informational duties, but leaving the technical realization to bilateral contracts between TSO and DSO or power generators respectively;

Technical minimum network access conditions to be considered by any type of facility that is to be connected to the transmission grid;

Management of energy transmission using the transmission grid;

26 The SAIDI indicator of 21.53 minutes (for electricity distribution) in 2006 was used as an argument by the industry that their networks managing their networks efficiently.

Appendix B: Germany

2-30

Network extension principally based on the (n-1) – criteria (break down of one system component shall not impair power feed-in to be delivered by the remaining n-1 components and still enable full energy supply); and

System operation, comprising system balancing, system planning, system control and load frequency-control.

The four German TSOs regard the Transmission Code as a compulsory basis for further bilateral agreements with market participants on power network access and usage.

VDN S 1000 transforms stipulations of the EnWG and other legal responsibilities into a guideline on necessary human resource qualification, indispensable technical equipment and appropriate organizational and procedural design of the technical operation of power networks. In detail, it specifies the need for the position of at least one technical operation manager (specialist, not generalist) and lists the technical equipment that he must employ to comply with the company’s legal obligation to guarantee security of supply. Both technical staff and facilities must be integrated into an effective organization scheme which explicitly defines decision authority, duties, processes and timing of actions;

The VDN Technical Guideline on Maintenance of Electrical Facilities (2006) is also a guideline which was derived from various legal stipulations for power network operators. It describes potential maintenance strategies, suggests a principle maintenance and repair procedure to follow, and identifies technical objects on each voltage level that are worth to be considered during the mentioned procedure. This guideline represents a descriptive listing of potential activities and recommendations without having a normative or binding character; and

DVGW27 is a technical standardization body in the field of production, transportation, distribution, and use of gas and water. It develops and introduces technical standards in cooperation with the gas and water industry. In the field of gas, DVGW specifies rules which apply to the following points: – production and conditioning; – compression and storage; – transport and distribution; – pressure modulation; – metering; – processing; – corrosion prevention; – pipe line installation and construction; and – certification.

27 Deutsche Vereinigung des Gas- und Wasserfaches e. V. – Technisch-wissenschaftlicher Verein / German Technical and Scientific Association for Gas and Water.

Appendix B: Germany

2-31

In summary, there is neither a legal nor a mandatory set of technical rules to operate the transmission and distribution networks and to make efficient use of existing assets. However, one of the aims of the revenue cap framework seeks to encourage and incentivize electricity and gas TSOs and DSOs to operate the networks efficiently.

Legal reference to the latest technical standards can be interpreted as an expectation to make use of state-of–the-art technology and comply with modern specifications. However, the above mentioned agreements and guidelines do not limit the TSO or DSOs to a certain portfolio of measures or procedures. Instead, they are free to decide how to operate their technical assets to meet legal requirements on network stability, reliability of energy supply, security of supply and limitation of disturbances.



In Germany there is no explicit legislation that addresses asset management. Similar to most other European countries, the German electricity market is built upon several levels of legislative and contractual provisions. These range from primary and secondary legislation via regulatory decisions to a number of industry documents and standard agreements, which sit underneath these. The German legislative framework consists of federal laws, ordinances and regulatory decisions, which are aimed at ensuring competitive power and gas (referred to as “energy”) supply and reliable operation of energy supply networks on a long-term basis. German legislation incorporates the legal demands of the European Union on the grid-bound energy supply.

Energy regulation is subject to the Energy Act (Energiewirtschaftsgesetz - EnWG), which came into effect on 29 April 1998. Due to the EU Liberalisation Directives 2003/54/EC (electricity), 2003/55/EC (gas) and 2004/67/EC (security of natural gas supply), this led to the amendment of the EnWG in 2005. The amended EnWG is directed towards the liberalization and deregulation of the German electricity and gas markets with the objective to promote competition within the common European market. One of the main changes brought about by the amended EnWG 2005 is the ex-ante regulation of network charges done by the BNetzA. Besides that, the Energy Act included rules concerning the separation (legal unbundling) of vertically integrated companies. The objective of the Energy Act is to establish non-discriminatory third party network access, as well as fair and efficient network charges, while at the same time offer a secure, cost-efficient, consumer-friendly, efficient and environmentally sustainable grid-based supply of electricity and gas to the general public. The EnWG deals in particular with the regulation and unbundling of network operations on the electricity and gas market.

At the primary legislation level, the Energy Act, in its latest version from 2005, provides the legal basis for the regulation of and access to the German energy markets. It commits energy supply companies to the target of a “preferably safe, cheap, consumer-friendly, efficient and

Appendix B: Germany

2-32

environmentally sustainable grid-bound public supply by power and gas”. It specifies the main principles of the overall market design and access to transportation and distribution networks and obliges energy supply companies to publish its technical minimum requirements for the connection and the operation of third party installations.

In order to implement the legal framework of the EnWG, and setting the overall price control a number of Ordinances have been developed. These include among others the Network Charge Ordinances for electricity and gas respectively (Netzentgeltverordnungen – StromNEV / GasNEV), the Network Access Ordinance for electricity and gas respectively (Netzzugangsverordnungen – StromNEV / GasNEV) and the Incentive Regulation Ordinance (Anreizregulierungsverordnung – ARegV) changing the so far cost-based regulation of network charges to a RPI-X regulation from January 1, 2009, on (for electricity, gas starts one year later). These ordinances set out detailed rules and conditions which must be adhered to by the utilities. Within these ordinances there are no formal or prescribed rules specific to asset management practices.

As highlighted previously, the Bundesnetzagentur is the Federal Network Agency to regulate the electricity, gas, telecommunications, post and railway. For the electricity and gas transmission and distribution networks its roles, responsibilities, and powers are set out in the amended Energy Act 2005. The Federal Network Agency’s central task is to:

Create the prerequisites for functioning competition on the upstream and downstream markets by unbundling and regulating the power and gas supply grids;

To ensure non-discriminatory network access and the control of the network usage rates levied by the power supply companies; and

The range of tasks also include the supervision of anti-competitive practices and the monitoring of the regulations concerning the unbundling of network areas and the system responsibility of the network operators.

In reference to the authorities of the federal states they are also empowered by the Energy Act 2005 and also have the main tasks and responsibilities similar to the Bundesnetzagentur as listed above. There are some slight differences between the Bundesnetzagentur and the authority of the federal states. For example, the Bundesnetzagentur is the representative regulatory authority when dealing with other regulatory authorities in the EU and elsewhere. For cooperation and collaboration with other regulatory authorities it is the Bundesnetzagentur that is the point of contact. The Bundesnetzagentur and the federal state authorities have set up working groups to exchange and discuss regulatory topics.

Appendix B: Germany

2-33


The Energy Law Paragraph 11 states that operators of energy supply systems are obligated to operate, maintain, and develop as needed a safe, reliable, and efficient energy supply system non-discriminatorily to the extent that is economically feasible and as such, in relation to asset management and investment planning, no such legal obligation such as specific codes and guidelines exists at present.

The only thing that comes close to an asset management context is the obligation of the utilities to submit information to the regulator and to other bodies such as the Federal Ministry for Economics and Technology regarding the status of the network infrastructure for the purpose of reporting requirements.

In terms of codes and rules these are normally voluntary and not legally binding but have usually been developed by the utilities themselves to implement and transfer the obligations set out in the relevant primary and secondary legislation. They set out best practice in order to run and operate the electricity and gas networks to a reasonable technical standard to meet the obligations specified in the Energy Act.


Transmission Code 2007 represents a voluntary set of rules, which was developed and introduced by the four German TSOs, without any formal industry consultation and/or approval by the regulator. The development of the code was not purely voluntary since the Energy Law obliges the Transmission System Operators to develop technical requirements for the connection to their networks and to publish them (EnWG, Paragraph 19), i.e., the TSOs were forced to create a set of rules. Amongst others, the Transmission Code spells out the main principles of providing a safe, secure and reliable transmission network as set in the Energy Act. Although the Transmission Code is not mandatory it provides the principles and best practice standards to implement the obligations of the Energy Act.

Electricity Distribution

Distribution Code 2007, similar to the Transmission Code, contains the role and responsibilities of a Distribution System Operator. It states explicitly the duties of a system operator on operating the network in a safe, secure, and reliable manner. It does not however contain details on how a distribution system operator should do this explicitly. However, a proper maintenance strategy is required to meet the rules set out in the codes.

Appendix B: Germany

2-34


In Germany, the provisions of the Energy Act are rendered more precisely by several ordinances at a secondary legislation level. The main ordinances specific for the utilities are:

Ordinance on Incentive Regulation (for electricity and gas); Ordinance on Network Access for Electricity (Netzzugangsverordnung,

Strom) and the Ordinance on Network Access for Gas (Netzzugangsverordnung Gas); and

The Ordinance on Network Charges for Electricity and (Netzentgeltverordnung Strom) the Ordinance on Use-of-System Charge for Gas (Netzentgeltverordnung Gas).

The utilities are legally obliged to abide by the rules and condition set out in these ordinances. These ordinances do not contain explicit asset management standards, procedures or guidelines. During the consultation phase of the new regulatory regime there was discussion to incorporate asset management in legislation and to establish a regulatory asset register over the last decades, but it was strongly opposed by the industry and finally dropped.



At present there are no explicit guidelines for the preparation of asset management plans. There are however instruments in place to promote and secure “efficient” investment of the network in order to abide by the Energy Act. These include monitoring of the utilities by the regulator, by means of regular reporting on the status of the network system and on investment planning behavior. For the purpose of technical information related to assets, the utilities are required to report to the regulator on:

Detailed technical data, for example, length of lines and cables/voltage or pressure level, installed transformer ratings;

Complete survey of the performance and the output of the grid including power and current of each voltage, transmission or pressure level;

Report of the status of the network; Extension and topology of the supplied area; and Monitoring of the security of supply including listings of breakdowns, risk

management and other resultant activities.

This information is not used for asset management purposes as such by the regulator but used for monitoring and reporting purposes. For example, in 2008 a report on the German gas and electricity gas market was published by the regulator containing information about the expenditure of the transmission and distribution networks (gas and electricity). For electricity distribution a total of 2.127 million Euros was invested by the distribution system operators in

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Appendix B: Germany

2-35

the distribution network infrastructure in 2007. A further 1.303 million Euros was spent on new construction, expansion, and development, as well as preservation/renewal of network infrastructure. For repairs maintenance 1.678 million Euros was spent.


There are no explicit regulatory guidelines for investment plans but there are certain reports that the regulator has to produce. For example, a report on the evaluation of network status and network development of the German electricity transmission network providers was published by the German regulator 2007. The TSOs are obliged to submit information as specified in the Energy Act Paragraph 12 every 2 years to the regulator on the status of their networks and upcoming network development plans.

In addition, Paragraph 21 of the Incentive Regulation Ordinance specifies that the network owners (electricity and gas) are required when requested by the regulator to submit a report to the regulator containing information on their assets and investment behavior. The purpose of this report is to assess whether the upcoming incentive regulation regime has no negative impact on the investment behavior of the companies, which in turn can impact the overall security of supply. However, this network specific information is not made public. The regulator only publishes a monitoring report containing aggregated numbers on the overall electricity and gas market in Germany. In this document, among others, details on the investment behavior, network condition, and network planning are summarized for the electricity and gas networks.

The Energy Act 2005 Paragraphs 12 and 14 require that the transmission and distribution system operator submit every 2 years (the first report submitted in February 2006) a report on the condition and status of their networks and details of their expansion/upgrading plans to the Federal Ministry of Economics and Technology (BMWi)28. Based on this information the BMWi publishes a monitoring report on the security of supply for electricity and gas networks. This report contains details of generation capacity, generation sources, quality of supply, and scope of network servicing by the electricity and gas TSOs and DSOs.

This following excerpt is a translation of a worksheet from the data collection template that needs to be submitted to the regulator. The information is a summary of additions/disposals of assets (fixed and intangible). In an additional worksheet details on each asset is collected. The regulator has determined 35 asset groups for electricity and 44 assets groups for gas including the respective asset life of each asset.

28 Bundesministerium für Wirtschaft and Technologie (BMWi).

Appendix B: Germany

2-36

Table 24: Worksheet of Data Required by German Regulator

Ans

chaf

fung

s- u

nd

Her

stel

lung

skos

ten

[€]

Zug

änge

[€]

Abg

änge

[€]

Um

buch

unge

n [€

]

Zus

chre

ibun

gen

des l

etzt

en

abge

schl

osse

nen

Ges

chäf

tsja

hres

[€]

Abs

chre

ibun

gen

(kum

ulie

rt) [

€]

Res

tbuc

hwer

t zum

31.

12.d

es

letz

ten

abge

schl

osse

nen

Ges

chäf

tsja

hres

[€]

Res

tbuc

hwer

t zum

31.

12.d

es

vorl

etzt

en a

bges

chlo

ssen

en

Ges

chäf

tsja

hres

[€]

Abs

chre

ibun

gen

des l

etzt

en

abge

schl

osse

nen

Ges

chäf

tsja

hres

[€]

Purc

hasi

ng a

nd

prod

uctio

n co

sts (

€)

Add

ition

s (€)

Dis

posa

ls (€

)

Tra

nsfe

r (€

)

App

reci

atio

n of

last

co

mpl

ete

fisca

l yea

r (€

)

Dep

reci

atio

n (c

umm

ulat

ive)

(€)

Res

idua

l boo

k va

lue

at

31.1

2 of

last

com

plet

e fis

cal y

ear

(€)

Res

idua

l boo

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at

31.1

2 of

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t to

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co

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fisca

l yea

r (€

)

Dep

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l yea

r (€

)

Assets Intangible Assets Fixed Assets Building & Land technical assets and machinery other Finanical Assets Shares in subsidiaries Securities 2.7 Lessons Learned and Future Areas of Focus

As the German regulatory environment for incentive regulation is currently at the very early stages there are certain areas which are still under discussion, especially in regards to the treatment of replacement expenditure under the investment budget mechanism. The German regulator decided upon the TOTEX approach to avoid the problem of substitution. This means the regulator does not differentiate between operating expense and capital expense but sets the efficiency factor on the basis of total costs (TOTEX). This also means that the regulator does not consider the investment plans of each individual utility.

In terms of asset management systems in the future, from the perspective of the regulated utility, they are being faced with detailed reporting requirements by the regulator especially concerning their investment behavior and also information on their existing assets. Some TSOs and DSOs, especially the larger companies, have already set up asset management

Appendix B: Germany

2-37

departments and are using special software to capture information regarding their assets and their investment behavior. Whether this will be a trend or a necessity for all the utilities is yet to be seen.

In regards to explicit asset management guidelines from the Bundesnetzagentur in the future, the industry was opposing this idea during the consultation rounds and at present this has not been implemented. However, depending on the developments in the discussions between the TSOs and DSOs and the regulator, this topic may be raised again in the near future.

Appendix C: Great Britain

3-1

3. Appendix C: Great Britain In Great Britain, there is a single regulatory body, Ofgem, responsible for the regulation of the gas and electricity markets. A fundamental part of this responsibility is the regulation of the transmission and distribution network businesses within each of these energy markets.

Ofgem was established as a combined electricity and gas regulatory body from its predecessors, Offer (electricity) and Ofgas (gas), by the UK government legislation under the Utilities Act of 2000. Ofgem was established to be independent of the government to allow the regulatory process to be free from political intervention to minimize the impact of changes in the government influencing regulatory policy and thus, creating unacceptable levels of uncertainty in the energy markets.

Ofgem is governed by an Authority which consists of executive and non-executive members (who bring experience from work in wider industry and social policy). As a total regulatory entity, Ofgem employs c.300 people, primarily based in London and has an annual budget of about £35m per annum, which is collected from licensed Great Britain generators, suppliers (retailers), and transmission and distribution network businesses for both electricity and gas.

The Authority is responsible for setting Ofgem’s policy priorities, which are formally set out within a business plan document published annually. However, Ofgem is obliged by the UK government to undertake Regulatory Impact Assessments for any major changes (as submitted via various Great Britain industry modification processes, although ultimate governance resides with the regulator) to ensure alignment with stated policies and/or as part of policy implementation. Nonetheless, Ofgem (and the decisions it makes in pursuing its policy objectives) is also subject to parliamentary scrutiny, appeals to the Competition Commission and potentially Judicial Review; where industry parties feel Ofgem has over-reached its powers or has acted inappropriately.

Under its statute, the principle duty of Ofgem is protecting consumers, which it undertakes in two ways:

1) Promoting effective competition, wherever appropriate; and

2) Regulating effectively the monopoly companies which run the gas pipes and the electricity wires.

It is this latter aspect which KEMA focuses upon within this report.

Ofgem also has other statutory obligations, priorities and influences, which are to:

Help secure Britain’s energy supplies by promoting competitive gas and electricity markets – and regulating so that there is adequate investment in the networks;


3-2

Help gas and electricity markets and industry achieve environmental improvements as efficiently as possible; and

Take account of the needs of vulnerable customers, particularly older people – those with difficulties and low incomes.



Electricity

In electricity, the following companies are subject to price control regulation and thus, regulatory review of their network investment plans and supporting asset management practices:

National Grid Company, which owns the electricity transmission network in England and Wales. It is important to note that National Grid also acts as the Great Britain System Operator (GBSO) and is responsible for real time operation of the entire Great Britain electricity transmission network – this is touched upon later in this section – but we do not include details for this activity in this Report;

Scottish Power and Scottish & Southern Energy, which each own electricity transmission and distribution networks in Scotland. Scottish Power owns the transmission and distribution networks in the south of Scotland and Scottish & Southern Energy owns the transmission and distribution networks in the north of Scotland; and

The seven companies responsible for electricity distribution in 12 regions known as Distribution Service Areas (DSAs) covering England and Wales. These companies are: CE Electric UK (Northern and Yorkshire regions), Central Networks (West Midlands and East Midlands regions), EDF Energy (Eastern, London and South East regions), Scottish Power (Merseyside and North Wales region), Scottish & Southern Energy (Southern region), Electricity North West (North West region), and Western Power Distribution (South Wales and South West regions).

Gas

In gas, the following companies are subject to price control regulation and thus, regulatory review of their network investment plans and supporting asset management practices.

National Grid Company, for gas transmission in Great Britain as a whole. It is important to note that, as for electricity transmission, National Grid acts as the Great Britain System Operator (GBSO) for gas transmission – we do not include details for this activity in this Report; and


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The four companies responsible for gas distribution in eight regions across Great Britain are: National Grid, who originally owned all eight regions but now own four under a single license as National Grid Gas Networks (North West, East Midlands and East Anglia, West Midlands and North London regions), Northern Gas Networks (North of England region), Wales & West utilities (Wales & West region) and Scotia Gas, which is part of Scottish & Southern Energy (Scotland and Southern England regions).


Electricity

The coverage of the 14 DSAs by each of the seven Great Britain DNO owning companies is illustrated in the map below (which also shows the Northern Ireland DNO, which is subject to a different regulatory regime as applied in Ireland).


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Figure 23: GB Distribution Network Owner (DNO) Geographic Areas and Ownership

Source: Electricity Network Association

Although National Grid acts as the single GBSO, there are three separate Transmission Owners (TOs) as indicated previously. Scottish & Southern Energy owns the transmission network for the same area of northern Scotland covered by its Scottish distribution area. Likewise, Scottish Power owns the transmission network for the same area of northern Scotland covered by its Scottish distribution area. National Grid owns the transmission for England and Wales (i.e., every where else in Great Britain). A geographic map of the network is provided below.


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Figure 24: GB Transmission Network

Source: National Grid’s GB (Electricity) Seven Year Statement


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Gas

National Grid, as the Great Britain gas transmission owner and operator (i.e., the GB TSO), has a network which covers all of Great Britain as illustrated below (showing the 12 LDZs).

Figure 25: GB Gas Transmission Network

Source: National Grid’s GB (Gas) Ten Year Statement

The coverage of each of the four Great Britain gas distribution companies (note Scotia Gas owns both Scotland Gas Networks and Southern Gas Networks) is illustrated in the map below.


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Figure 26: GB Gas Distribution Networks Geographic Areas and Ownership


From the above diagram it can be seen where the regions of ownership combine two or more of the LDZs.

3.1.3 Key Technical and Financial Statistics per Utility

Electricity Networks Overview

Due to the history of development of the electricity market in Great Britain, network information is often summarized in three parts; reflecting the transmission ownership areas of:

1) National Grid (England and Wales);

2) Scottish Power (southern Scotland); and

3) Scottish & southern Energy (northern Scotland).

Some key statistics collated by the Energy Networks Association (ENA), which represents all Great Britain electricity and gas network companies, provides the following statistics:


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Table 25: GB Electricity Networks – Headline Statistics


It can be seen that the majority of network infrastructure is in England and Wales. The different scale is further emphasized by comparing the England and Wales transmission network (as owned by National Grid) with the transmission network for Scotland as a whole (owned by Scottish Power and Scottish & Southern Energy).


Key facts and figures for the 14 GB electricity DNOs

The table below provides an overview of customer numbers and units distributed for each of the 14 DNOs (Source: Ofgem).

Table 26: Customer Numbers and Units Distributed of the GB DNOs by Voltage Level

DNO No. of customers (million)

Total units distributed

(TWh)

EHV units

(TWh)

HV units

(TWh)

LV1 units

(TWh)

LV2 units

(TWh)

LV3 units

(TWh)

CE – NEDL 1.51 16.69 2.54 3.63 0.64 0.65 9.23

CE- YEDL 2.14 24.07 1.39 8.13 1.11 1.12 12.32

CN – East 2.42 28.19 0.74 10.57 5.33 2.71 8.86

CN – West 2.30 27.22 0.85 10.02 1.71 1.80 12.84

EdF – EPN 3.38 34.22 0.68 8.11 6.79 3.88 14.76

EdF – LPN 2.08 25.52 0.53 6.10 0.92 0.94 17.03


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DNO No. of customers (million)

Total units distributed

(TWh)

EHV units

(TWh)

HV units

(TWh)

LV1 units

(TWh)

LV2 units

(TWh)

LV3 units

(TWh)

EdF – SPN 2.11 20.75 1.85 2.78 3.07 2.13 10.91

ENW 2.27 25.22 0.81 7.92 1.17 1.66 13.67

SP – S Scots 1.91 22.56 2.15 4.90 1.17 2.66 11.69

SP – Manweb 1.43 16.94 2.43 4.40 0.73 0.75 8.62

SSE – N Scots 0.67 8.41 0.43 1.18 1.69 2.00 3.10

SSE – Southern 2.71 32.32 2.30 8.25 1.41 2.55 17.81

WPD – S Wales 1.04 12.52 2.95 2.70 0.44 0.46 5.97

WPD – S West 1.36 15.12 0.68 3.66 1.26 1.64 7.88

TOTAL 27.33 309.75

Similarly, the table below provides an overview of key technical characteristics of the distribution networks for each of the 14 DNOs (Source: Ofgem).

Table 27: Key Technical Characteristics of the GB DNOs

DNO Total geographic area (million sq.

km)

Total overhead line (km)

Total underground cables (km)

Total Network Length (km)

CE – NEDL 14.4 15,023 24,587 39,610

CE- YEDL 10.7 15,777 40,408 56,185

CN – East 16.0 23,263 44,739 68,002

CN – West 13.0 24,283 36,209 60,492

EdF – EPN 20.3 35,002 56,290 91,292

EdF – LPN 0.7 41 30,397 30,438

EdF – SPN 8.3 12,235 33,130 45,365

ENW 12.5 13,747 44,284 58,031

SP – S Scots 23.0 24,460 41,137 65,597

SP – Manweb 12.2 21,668 24,204 45,872

SSE – N Scots 54.5 30,672 14,332 45,004

SSE – Southern 16.9 27,712 46,092 73,804

WPD – S Wales 11.8 18,465 14,556 33,021

WPD – S West 14.4 29,437 19,358 48,795

TOTAL 228.7 291,785 469,723 761,508


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The table below provides further detail of the network at different voltage levels for each of the 14 DNOs (Source: Ofgem).

Table 28: Network Circuit Assets of the GB DNOs by Voltage Level

132kV 66kV 33kV HV LV DNO

OHL Cabl OHL Cable OHL

Cable OHL Cable OHL Cable CE – NEDL 604 73 1,02 437 355 417 10,08 7,427 2,956 16,23CE- YEDL 1,222 196 941 58 1,29 1,366 9,797 10,80 2,523 27,98CN – East 2,158 193 10 10 2,86 1,429 12,90 12,20 5,325 30,90CN – West 1,405 298 809 18 1,04 376 14,72 11,59 6,301 23,91EdF – EPN 2,356 231 0 0 3,87 2,534 19,29 17,22 9,474 36,30EdF – LPN 28 470 12 445 0 638 1 9,072 0 19,77EdF – SPN 1,179 333 0 0 1,31 1,266 5,593 11,03 4,149 20,49ENW 1,332 249 0 0 1,38 1,785 7,994 11,26 3,032 30,98SP – S Scots 0 0 0 0 2,96 1,838 16,95 15,18 4,544 24,11SP – Manweb 1,299 213 0 0 2,00 1,528 13,05 6,398 5,310 16,06SSE – N Scots 0 0 0 0 5,32 649 21,10 4,766 4,244 8,917 SSE – Southern 1,920 394 6 163 3,45 1,795 13,39 14,33 8,929 29,40WPD – S Wales 1,165 71 355 15 1,46 380 12,31 4,970 3,165 9,120 WPD – S West 1,372 58 0 0 2,84 1,030 17,43 6,444 7,793 11,82

Overview of revenue allowances for the 14 GB electricity DNOs

The table below provides details of the underlying capital expense, operating expense, and consequential derived revenue allowances allocated to the Great Britain electricity DNOs for the period 2005/06 – 2009/10 (Source Ofgem: 2002/03 prices).

Table 29: Capex, Opex and Derived Revenue Allowance for GB DNOs for 2005/06 – 2009/10

DNO Capex (£m) Opex (£m) Revenue (£m)

CE – NEDL 277 215 785

CE- YEDL 371 260 1,025

CN – East 501 325 1,230

CN – West 485 305 1,210

EdF – EPN 697 410 1,455

EdF – LPN 452 260 1,145

EdF – SPN 487 260 855

ENW 466 290 1,120

SP – S Scots 361 280 1,470

SP – Manweb 404 180 875

SSE – N Scots 204 190 850

SSE – Southern 561 345 1,700

WPD – S Wales 283 235 895

WPD – S West 186 200 730

TOTAL 5,734 3,795 15,345


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As a consequence of the ongoing price control, the resultant Regulatory Asset Value (RAV) for the 14 Great Britain DNOs as at the end of 2006/2007 is outlined below.

Table 30: Regulatory Asset Values of the GB DNOs

DNO RAV as at end 2006/07 (£m)

CE – NEDL 731 CE- YEDL 963 CN – East 1,148 CN – West 1,216 EdF – EPN 1,341 EdF – LPN 1,079 EdF – SPN 787 ENW 1,116 SP – S Scots 1,365 SP – Manweb 978 SSE – N Scots 807 SSE – Southern 1,538 WPD – S Wales 664 WPD – S West 857 TOTAL 14,587


Key facts and figures for the three Great Britain electricity TOs

At a transmission level, while there are three Transmission Owners (TOs), one of these (National Grid) also acts as GBSO.

Some key headline statistics for the three TOs are provided below.


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Figure 27: Headline Statistics for the 3 GB Transmission Owner (TO) Networks

Source: National Grid

The diagram above indicates that National Grid acts as the GBSO (and thus is effectively a TSO for England and Wales). However, as previously highlighted in this report, we only review the TO function. In addition to the above headline company statistics, the table below gives an indication of scale of the transmission network in England and Wales versus the combined network in Scotland.

Table 31: Key Technical Characteristics of the GB Electricity Transmission Networks

Item England & Wales

Scotland

Network Metrics No. of sites 300 260 No. of busbars 1,060 1,000 No. of switches 12,441 10,000 No. of lines 853 650 Demand points 350 250 No. of transformers & quad boosters

1,172 570

Circuit route km 7,000 8,700 Other Metrics Generating Units 257 130 Demand max (GW) 55,000 7,000 Outage requests/yr 3,500 1,500


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Overview of revenue allowances for the three Great Britain electricity TOs

The table below provides details of the underlying capital expense, operating expense, and consequential derived revenue allowances allocated to the Great Britain electricity TOs for the period 2007/08-2011/12 (Source Ofgem: 2004/05 prices).

Table 32: Capex, Opex and Derived Revenue Allowance for GB TOs for 2007/08 – 2011/12

TO Capex (£m) Opex (£m) Revenue (£m)

National Grid 2,997 1,289 5,465 Scottish Power 608 143 780 SSE 181 46 250 TOTAL 3,786 1,478 6,495

At the commencement of current price control, the Regulatory Asset Value (RAV) for each of the three Great Britain TOs as at the end of 2006/2007 is outlined below (Source Ofgem: 2006/2007 prices):

Table 33: Regulatory Asset Values of the GB TOs

DNO RAV as at end 2006/07 (£m)

National Grid 5,416 Scottish Power 507 SSE 154 TOTAL 6,077

Gas Networks Overview

The majority of gas is delivered to reception points (called beach terminals) by gas producers operating rigs in about 100 fields beneath the sea around the British Isles. After treatment, which includes checking the quality, adjusting the calorific value (CV) – the amount of energy contained in the gas – it is transported through 275,000 kilometers of steel pipelines, iron and polyethylene mains and services to supply the customers who use it.

The gas infrastructure comprises the national transmission system (NTS), which was built in the 1960s, and local distribution zones. These networks link together, forming the basis for moving gas from coastal reception points to customers who require it. The NTS is the larger-scale part of the network (which operates up to 85 bar pressure) to transport gas to large consumers and the Local Distribution Zones (LDZs). The 12 Local Distribution Zones are within eight regional distribution networks (whose area and ownership is outlined above).


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North West, West Midlands, and London – as owned by National Grid Gas Networks;

East of England (East Anglia and East Midlands LDZs) – as owned by National Grid Gas Networks;

North of England (North and Yorkshire LDZs) – as owned by Northern Gas Networks;

South of England (South and South East LDZs)– as owned by Scotia Gas Networks (SSE);

Scotland – as owned by Scotia Gas Networks (SSE); and Wales and the West (Wales and South West LDZs) – as owned by Wales &

West Utilities.

Gas Distribution

Key facts and figures for the four GB gas DNOs

The following tables provide key statistics regarding the networks and customers for each of the four Gas DNOs (Source: Ofgem).

Table 34: Key Facts and Figures for National Grid Gas Networks


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Table 35: Key Facts and Figures for Northern Gas Networks

Table 36: Key Facts and Figures for Scotia Gas Networks

Table 37: Key Facts and Figures for Wales & West Utilities


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Overview of revenue allowances for the four GB Gas DNOs

The table below provides details of the underlying capital expense, operating expense, and consequential derived revenue allowances allocated to the GB gas DNOs for the period 2008/09 – 2012/13 (Source Ofgem: 2005/06 prices).

Table 38: Capex, Opex and Derived Revenue Allowance for GB Gas DNOs 2008/09–12/13

Gas DNO Capex (£m)

Opex (£m) Revenue (£m)

East of England 715.4 507.0 2,152.4 London 689.5 380.5 1,410.5

North West 618.0 413.5 1,495

National Grid

West Midlands 448.3 313.0 1,158.5 Northern Gas Networks Northern 637.7 395.0 1,451.5

Scotland 451.8 326.5 1,007.5 Scotia Gas Networks

Southern 1,123.3 589.0 2,340.5 Wales & West Utilities Wales & West 652.0 394.5 1,336.5 TOTAL 5,335.9 3,319 12,352.0

The total RAV for the four Gas DNOs above as at end 2006/2007 was c. £11.431bn.

Gas Transmission

Key facts and figures for the GB gas TO

The national transmission system (NTS) is the high pressure (up to 85 bar) tier of the Great Britain gas network, moving gas from beach terminals to very large industrial customers and power stations and to exit points to gas distribution networks. The NTS also takes gas to and from storage facilitates and to other interconnected high pressure networks in Northern Ireland and Eire and mainland Europe.

The NTS consists of more than 6,400 kilometers of steel pipeline operating at high pressures of up to 85 bar (85 times normal atmospheric pressure). The gas is pushed through the system using 24 strategically placed compressor stations.

From 140 off-take points, the NTS supplies gas to 40 power stations, a small number of large industrial consumers and the 12 local distribution zones that contain pipes operating at lower pressures, which eventually supply the consumer.


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Gas demand met by the NTS can reach 450mcm/day on a cold peak winter day, but is highly sensitive to weather due to the high use of gas in domestic heating. The chart below illustrates 2007/2008 daily outturn demand and how it sat within seasonal cold/warm weather bands.

Figure 28: Outturn Daily GB Gas Demand and Relation to Cold/Warm Weather Demands

Source: National Grid

Over the course of a typical year, the system throughput of gas on the NTS amounts to c. 100Bcm, which equates to c. 1,100TWh.

Overview of revenue allowances for the GB Gas TO

The table below provides details of the underlying capital expense, operating expense, and consequential derived revenue allowances allocated to the GB gas TO for the period 2007/08 – 2011/12 (Source Ofgem: 2004/05 prices).

Table 39: Capex, Opex and Derived Revenue Allowance for GB Gas TO 2007/08 –11/12

TO Capex (£m) Opex (£m) Revenue (£m)

National Grid 2,981 688 2,455

The total RAV for the Great Britain Gas TO as at end 2006/2007 was c. £2.981bn.


Details of the companies, which in combination own all of the gas and electricity transmission and distribution networks in Great Britain, are provided below (Source: Electricity Network Association).


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Table 40: GB Network Utility Ownership

CE Electric UK www.ce-electricuk.com CE Electric UK, through its subsidiaries Northern Electric Distribution and Yorkshire Electricity Distribution, delivers electricity to 3.7 million customers throughout the North East of England, Yorkshire and north Lincolnshire. It is owned by MidAmerican Energy Holdings Company.

Central Networks www.central-networks.co.uk Central Networks is the new name for Midlands Electricity and East Midlands Electricity. The company brings power to 4.8 million customers across the East and West Midlands through 133,000 km of underground and overhead cables and via almost 97,000 substations. Central Networks covers an area from the Peak District in the north to parts of Bristol in the south, and from the Welsh Borders to the Lincolnshire Coast.

EDF Energy www.edfenergy.co.uk EDF Energy is one of the largest energy companies in the UK. Over a quarter of the UK population, in London, the South East and East of England benefit from EDF Energy's distribution of electricity. EDF are also a major generator and supply electricity and gas to over 5 million customers through their regional brands: London Energy, SWEB Energy and Seeboard Energy.

Electricity North West Limited www.enwltd.co.uk ENW owns the electricity distribution network in North West England, distributing electricity to customers’ homes on behalf of the supply companies. Serving 2.3 million customers in the North West of England. Customers receive their electricity bill from supply companies who pay ENW for use of the electricity network. Please note: UUE is now part of ENW.

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National Grid www.ngtgroup.com National Grid is one of the world's largest utilities, focused on delivering energy safely, reliably and efficiently. They own and operate gas and electricity transmission and gas distribution networks in the UK and US and electricity distribution networks in the US.

Northern Gas Networks www.northerngasnetworks.co.uk Northern Gas Networks are the company responsible for distributing gas to homes and businesses across the north of England, an area covering West, East & North Yorkshire, the North East and northern Cumbria. Their network comprises of 36,000 km of gas pipes - that’s enough to travel from Leeds to Sydney, Australia, and back again. Northern Gas Networks are the company responsible for distributing gas to homes and businesses across the north of England, an area covering West, East & North Yorkshire, the North East and northern Cumbria.

Their network comprises of 36,000 km of gas pipes - that’s enough to travel from Leeds to Sydney, Australia, and back again. Northern Gas Networks do not own the gas; they transport it on behalf the companies who do, delivering it to users 24 hours every day. Northern Gas Networks is an essential element in the daily heartbeat of the region. Northern Gas Networks take extremely seriously their responsibilities as the provider of the fuel of choice; aiming to provide the best in customer service and to add value in all our activities. They have strong ownership behind us and aim to become an integral part of the communities they serve.

Scottish and Southern Energy www.scottish-southern.co.uk Scottish and Southern Energy (SSE) owns one transmission network and two distribution networks totaling 123,000 km of overhead lines and underground cables. The company covers one third of the UK landmass and delivers electricity to over 3.3 million customers. In addition to its networks business, SSE supplies gas and electricity to over eight million customers, it is the largest generator of renewable energy in the UK and it is involved in energy services, gas storage, contracting, retailing and telecoms.

Scotia Gas Networks (SGN) is the holding company of Scotland Gas Networks, Southern Gas Networks, SGN

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Connections, SGN Contracting and SGN Metering. Formed on 1 June 2005, SGN is now the UK’s second largest gas distribution company, operating two of the largest regional gas networks. With operational regions covering over 50% of the UK landmass and employing around 4,000 staff, SGN provides a safe and reliable supply of natural gas to 5.7 million customers through 74,000 kilometers of gas mains.

ScottishPower www.scottishpower.com With the integration of Scottish Power & Iberdrola now complete Scottish Power is focused on three main areas; Transport & Distribution through Energy Networks, Generation & Supply through Energy Wholesale & Retail and Canadian gas storage through PPM Canada

Wales & West Utilities Ltd www.wwutilities.co.uk Wales & West Utilities Ltd - formerly part of Transco - was launched on 1 June 2005. As a regulated gas distribution business with around 34,000 km of gas distribution pipelines located in Wales and the South West of England, the company's main offices are in Newport and it serves a catchment area with a population of 7.4 million. Wales & West Utilities' primary role - undertaken on behalf of 'gas suppliers' - is to transport gas to the gas meters of homes and businesses in Wales and the South West of England, from the Northern Welsh border to Cornwall.

Western Power Distribution www.westernpower.co.uk Western Power Distribution operates and maintains the electricity distribution network in South West England and South and West Wales. It delivers electricity to 2.5 million customers over a 26,000 sq kms service area.


This section describes the regulatory approaches, practices, and methodologies used in the assessment of network businesses’ capital investment plans by Ofgem. After an initial overview it provides a detailed discussion. As this covers all the network businesses that Ofgem regulates (gas and electricity transmission and gas and electricity distribution) we seek

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to highlight key areas of general commonality, key areas of difference between transmission and distribution and key areas of difference between gas and electricity.

3.2.1 Overview of Ofgem’s Approach to Assessment of Utility Investment Plans

Overall Process for Regulating Network Utilities – Price Controls, Revenue Recovery and Setting of Tariffs

Application of Price Controls - Fundamental to the regulation of the GB transmission and distribution businesses are regulator Price Control Review processes. These consist of a major cyclical review of the network businesses to set revenue allowances plus associated incentives and reporting measures for 5 year periods. Due to the timing of deregulation in gas (1986) and electricity (1990) and to enable Ofgem to conduct these cyclical reviews effectively, the 5 year periods are staggered for:

Gas and electricity transmission – the current price control period is 2007/08-2011/12;

Gas distribution – the current price control period is 2008/09-2013/14; and Electricity distribution – the current price control period is 2005/06-2009/10.

To give an indication of the extensive nature of these Price Control Reviews conducted by Ofgem, the initial stages of the current Distribution Price Control Review (known as DPCR5) for electricity Distribution Network Owners (DNOs) began in Spring 2008 and will run throughout 2009 (i.e., they are conducted over a c.18 month timeframe). At the end of 2009, Ofgem will issue its Final Proposals for each of the DNOs to accept or reject allowances for capital expense and operating expense for the period 2010/11-2014/15. Should a DNO reject the final proposals for its business as being unduly financially challenging, this automatically triggers a referral to the Competition Commission for review. However, to date there has never been such a referral by any of the network businesses (gas or electricity, transmission or distribution).

Recovery of Regulated Revenue: Once price control settlements have been determined for a 5 year regulatory (price control) period, including any mechanism for varying revenues in the light of uncertainties of investment/cost drivers within that period, Ofgem adopts a hands off process of regulation. The price control effectively determines the annual revenues for each year of the regulatory period, which the regulated network utilities can seek to recover from its relevant customers (whether that is directly or indirectly as part of another party’s charges (e.g., a domestic bill will contain an element of costs for each of transmission and for distribution).

Apart form in exceptional circumstances (as discussed below), these revenue streams are effectively set and annual performance of the network utilities does not affect these. Thus, if operating costs in a given year are higher than expected then, in principle, the network utility


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would bear the Profit & Loss hit (as long as this was not deemed to be unreasonable – hence provisions for exceptional circumstances).

Setting of Tariffs: How a network utility sets its tariffs (postage stamp, locational LRMC based, etc.) is governed by a separate charging methodology governance process which applies to the relevant group of network utilities. This governance process was established by Ofgem and while it is administered by the relevant network utilities (who have ownership of the charging methodologies), who are able to propose methodology changes in the light participant feedback, changing market environment, etc., Ofgem has the ultimate veto on any proposed change (and thus, effectively approves the applicable charging methodology for each network utility).

Tariffs are set annually ex-ante, taking into account baseline price control revenues and relevant modifications to take into account impact of incentive and uncertainty mechanisms in place; and any anticipated over or under recoveries of revenue from the preceding year. The exact tariff arrangements for each of electricity transmission, gas transmission, electricity distribution and gas distribution, differ, reflecting amongst other things, the different inherent characteristics of these networks and their interface with the wider market.

The exact tariffs are not subject to explicit review by Ofgem given they are set in accordance with the formal charging methodologies approved by Ofgem, although Ofgem can review relevant elements of a network utility’s charges where a customer raises a complaint.

Fit of Investment Plan within Price Control Review Process

It is this Price Control Review process which Ofgem uses to conduct assessment of utility investment plans. In other words, on a cyclical basis, Ofgem assesses the merits of a 5 year investment plan submitted by the network business as part of its overall submission for a derived annual revenue allowance over the 5 years of the next price control period.

It is important to note that the detail of the submitted investment plans from transmission and distribution businesses are not approved by the regulator, rather the level of revenue and potential change to the Regulatory Asset Base (RAB) that it implies. In other words, a network business is allowed some flexibility during the 5 year plan period and is not committed to implement the investment plan exactly (e.g., scheme by scheme) but is expected to implement much of what was proposed.

Thus, while there is post-event review (at the time of setting the next price control) of outturn investment for a price control period versus that forecast ex-ante – giving evidence of asset management credibility – network businesses are allowed to manage their activities as they see fit within a regulatory period without intrusive regulation (i.e., Ofgem does not conduct further assessment of investment plans and how they change/evolve within a given price control period). This is very different from some regulatory regimes, such as electricity transmission in New Zealand.


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Annual Monitoring of Investment within Price Controls

Over time, a number of annual regulatory reporting and incentive mechanisms have been developed to monitor and influence company behaviors throughout the 5 year price control period. These annual processes do not specifically relate to assessment of utility investment plans, which are conducted under the major cyclical review. Enhanced monitoring and incentive mechanisms effectively reduce the regulatory burden during Price Control Reviews by providing a flow of information over time. These annual reporting processes and incentives perform a useful role and are described later in this report.

Treatment of Uncertainty Relating to Investment Plans

In almost all circumstances the setting of regulatory revenue allowances and mechanisms for a price control period is assumed to be set to accommodate all reasonable events which may arise during that time. In relation to investment plans this means that if circumstances arise which lead to changes in numbers or types of connections or a change in understanding of asset/network condition and performance for example, then the network utilities are expected by Ofgem to review their investment plans and change accordingly to reflect these changing circumstances and thus, different priorities and needs.

Ofgem does not view the implicit allowance for capital expense within a regulatory settlement to represent some form of fixed budget. In other words, if market circumstances or asset management needs change such that more or less capital expense is required to be invested by the network utilities to meet planning standards and performance requirements, then they are expected to do so without recourse to the regulator. Deviations in outturn capital expense may be offset by counter-deviations in operating expense and other financial factors impacting on costs incurred by the network utilities. Thus, such changes are almost always addressed in adjustments to, for example, the RAB of network utilities at the time of the next Price Control Review.

In looking to determine a price control for a forthcoming regulatory period, there can be potential major investment needs of either unusual magnitude and/or uncertainty. An example was the large volume (up to 15GW c.f. existing 60GW of generation capacity) of potential renewables connections in Scotland and the consequential impact on the need for transmission investment as seen at the time of TPCR4. This was dealt with by ring-fencing the relevant related investment and treating this is a flexible manner within the price control (i.e., the associate revenue was only made available as and when the volume of renewables connection became more clear and the investment need more certain). Thus, the principle/mechanism was agreed and put in place at the time of the price control settlement but activated/applied within the regulatory period by the TOs formally notifying Ofgem.

For uncertainties of lesser magnitude, such as general level of load connections for distribution, there was a mechanism within the price control revenue formulae which explicitly linked levels of connections capital expense to numbers of connections and GW of


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load connected. Again, this allows a price control to be set in the 5 year cycle with uncertainties dealt with mechanistically within that period avoiding the need for intrusive regulation year on year.

Treatment of Exceptional Circumstances Relating to Investment Plans

Allowing for the above mechanisms used to try to remove the need for regulatory intervention within a price control period, exceptional circumstances may arise. In these circumstances, (i.e., where companies feel revenue allowances are insufficient for them to accommodate costs faced), the network utilities are entitled to formally approach Ofgem within a price control period with a view to obtaining additional funds.

Ofgem will then review the case put forward to deem whether: a) it is truly an exceptional circumstance; b) it really cannot be funded by the existing settlement via re-prioritization of other activities without compromising safety, or performance; and c) what the appropriate magnitude of extra funds might reasonably be. Thus, they may reject the case on the grounds of merit or manageability or accept the case and approve funds which may be lower than requested by the network utility or utilities involved.

Such events are rare and especially so for asset management related investment which is expected to be controllable and predictable within reasonable tolerances by the network utilities. However, an example of where this has occurred is in Great Britain electricity distribution where newly introduced Health and Safety legislation during the DPCR4 period imposed substantial and mandatory requirements on GB DNOs to undertake work to ensure vertical and horizontal clearances of towers were above defined distances.

3.2.2 Detail of Ofgem’s Approach to Assessment of Utility Investment Plans

Although the generic process for assessment of utility investment plans as described above is consistently applied across gas and electricity and across transmission and distribution, Ofgem’s detailed approach varies slightly within each specific Price Control Review process to reflect the individual characteristics of the type of network business investment plans under evaluation.

In this subsection we identify where the detailed investment plan assessments have:

Areas of general commonality; Areas of differentiation between transmission and distribution; and Areas of differentiation between gas and electricity.


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Areas of General Commonality Under each Price Control Review, there are a number of areas of general commonality in:

Process/approach, which Ofgem applies to the assessment of utility investment plans; and

Assessment of aspects of the investment plans and their derivation, etc., within overall asset management practices.

Process/Approach for Review of Investment Plans

There is general commonality in the process which Ofgem adopts and the approach it employs to undertake assessment of utility investment plans; as outlined below:

At the start of each Price Control Review process, Ofgem will publish an initial consultation document where it sets out: a) the high level approach and timetable it intends to apply; b) key high level issues and themes it wishes to address areas; and c) its intended areas of focus in regards to past, current or projected events/circumstances. In the case of investment plans this will capture key milestones for data provision, proposed means of scrutiny/assessment and key aspects for review (e.g., consideration of and reduction of environmental impact). This gives the network businesses an opportunity to understand, comment on and potentially alter the Price Control Review process to be implemented at the outset.

The above initial document will usually be followed by one (sometimes two) subsequent Price Control Review consultation documents where Ofgem expands upon policy issues and areas of focus for its review. In the context of investment plans this can cover a range of issues such as consideration of non-investment solutions to network development, protection of the environment (e.g., investment in low losses equipment) and address network resilience and network risk issues.

These documents enable the network businesses to begin to engage with Ofgem on high-level policy issues for the forthcoming Price Control Review (and thus, how it may shape the Price Control Review settlement determination, etc.) in written responses.

The above early consultations will run in parallel with a sequence of bilateral meetings at the Director level between Ofgem and each network business. These meetings enable high-level discussions of the key issues at an individual business level. Thus, for example, one business may have a significant issue with cable performance which they feel requires a major asset replacement program; whereas another business may have more concern regarding volume of potential new connections it will need to


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accommodate and thus, a high degree of uncertainty over required investment (what and where).

The bilateral meetings will be supplemented by multi-lateral meetings consisting only of the network businesses and thus, remain confidential. These meetings will tend to focus on various high-level topics such as Environmental, Customer Service, Network and Financing.

More recently, Ofgem has also introduced programs of workshops/meetings involving either all the impacted network businesses to review particular topics or all interested stakeholder groups, (e.g., end customers, generators, suppliers, interest groups, development agencies and environmental groups).

While this multi-lateral process will only have access to high-level summarized information deemed to be non-confidential (thus, will not see the detail of network business investment plans), it does provide a forum for enabling more informed comments from all parties on universal issues affecting all the network businesses on subjects ranging from the replacement of aging infrastructure to comparative analysis of undergrounding policies and associated visual amenity implications.

The network utilities’ own stakeholder events (which Ofgem has required them to hold on an annual/bi-annual basis) also provides Ofgem with additional insight of stakeholders’ views of different network utilities’ performance and plans and is used in their review of the reasonableness/justification of network utility price control submissions – indeed can lead to differing outcomes across utilities reflecting differing stakeholders in different network utility areas and consequentially differing priorities for the each network utility to address.

However, a pivotal stage in the process to assess investment plans is completion and submission of a comprehensive (standardized) Business Plan Questionnaire (BPQ) from each network business. This BPQ is sometimes split into a Historical BPQ (HPBQ) covering the current price control period (i.e., that preceding the one for which allowances are to be set) and a Forecast BPQ (FBPQ) focusing on the next price control period for which revenue allowances are to be set. The BPQ is usually structured as a narrative description of investment requirements and a large Excel file(s) containing a number of worksheet templates covering all facets of the regulated network businesses (financial, technical, commercial, etc.). In these BPQs, the data and information requirements are described in detail which must be provided by each network business.


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The issuance and responses to these BPQs represent major milestones in the Great Britain Price Control Review process and triggers a change in focus from initial discussion of high-level issues to a focus on detailed assessment for the remainder of the Price Control Review period. Furthermore, the BPQ is the first point at which Ofgem (and its supporting consultants) have sight of the detailed forward investment plans and preceding outturn investment under current investment programs. Thus, it is at this stage that rigorous and detailed assessments of what investments are proposed at what cost and why, commences.

Subsequent to the receipt of BPQ submissions, a process of review and challenge will commence. Driven by Ofgem, but usually supported by a range of independent consultants, this forms the basis of the Price Control Review process and is typically completed over a period of one year. This assessment will consist of an iterative process of detailed analysis supported by: a) an ongoing written Question & Answer (Q&A) process; b) supporting bilateral workshops and meetings; and c) site visits.

During the above “review and challenge” process, Ofgem will produce an “Initial Proposals” public consultation document in which it outlines initial assessments and policy direction which will influence the eventual price control settlements. Separate bilaterally confidential initial proposals and supporting documents will also be sent to each network business at this stage.

This combined approach gives both the network businesses and wider stakeholder groups (including institutional investors) an indication of price control settlement direction and highlights Ofgem’s initial observations, the key issues to be explored further and next steps.

This consultation phase also provides a major opportunity for network businesses to respond to Ofgem’s observations, conclusions and provisional recommendations and to focus the dialogue and interaction in the remaining period to resolve outstanding issues, areas of disagreement, etc., and thus, achieve a mutually acceptable outcome.

At the end of the “review and challenge” phase, Ofgem will issue its Final Proposals. It is at this stage that each relevant network business has to determine whether to accept or reject these.

An example of the Price Control Review process that Ofgem adopts and the timeframes in which it is conducted is provided by the diagram below, which illustrates the process currently being applied for its review of the Great Britain electricity distribution companies.


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Figure 29: GB Network Utility Price Control Review Process Example – GB DPCR5 Process

Source: Ofgem

Assessment of Investment Plans and Asset Management Practices

In addition to the assessment process, there are also some broad areas of commonality in the focus of assessment of the investment plans and the underpinning asset management practices. A generic list of the topics and issues that Ofgem typically examines is as follows:

Overall asset management philosophy: – asset management policy and procedure documents – relevant asset management accreditations (e.g., PAS 55) – key policy trends/recent changes.

Asset management organization and structure

Supporting IT systems for asset management: – asset databases including for example asset registers, asset inspection and

maintenance records, asset condition records – outage planning/scheduling systems

o inspection and maintenance scheduling o condition assessment scheduling

– tools used or under development in the field of asset management.

Investment planning: – overall process investment planning and scheme development process; – allocation of investment between Load Related Expenditure (LRE) and

Non-Load Related Expenditure (NLRE). The former typically relates to required network investment to meet demand and generation changes,


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whereas the latter relates to typical relates to asset replacement/renewal within the utilities’ service area.

It is important to note that where LRE and NLRE investment drivers overlap (i.e.,. are coincident) or interact (i.e.,. drive investments at a site in close time proximity), Ofgem will scrutinize whether the relevant network utility has addressed investment requirements efficiently, e.g., not replace an asset twice due to replacement needs followed by customer connection needs, but oversize at time of asset replacement to accommodate subsequent customer connection needs.

– asset replacement undertaken within load related scheme expenditure, (i.e., combinations of LRE and NLRE)

– asset replacement which has delivered enhanced system capacity (i.e., not “like-for-like” asset replacement and sometimes referred to as “betterment”)

– coordination with interfacing networks (transmission and/or distribution) – investment plan delivery

Asset replacement modeling (a top-down approach to investment planning): – degree of emphasis on asset replacement modeling in the planning

process – development of asset life assumptions for various asset categories – comparison of asset lives with other GB and international operators

Condition assessment (bottom-up approach to investment planning): – inputs from routine inspection and maintenance activities – asset condition assessment techniques employed – review of utility asset condition information quality and accessibility – residual asset life assessment techniques employed

Integration of top-down and bottom-up approaches to ensure the outputs of modeling exercises are aligned with the actual network under consideration

Unit costs and scheme costs: – scheme costing approach, methods and tools – analysis of a sample of schemes from inception to delivery – derivation of unit costs – approach, supporting evidence and justification – cost indices for external “uncontrollable” factors

Risk and performance measurement techniques: – asset (equipment) risk – network (system) risk


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Engineering operating expense and NLRE optimization: – levels of routine maintenance activities undertaken during the current

price control period (and influence on asset condition and asset replacement needs)

– outsourcing of engineering operating expense activities

Investigation of trade-off decisions between operating expense and capital expense

The role of procurement: – interaction with the main asset management organization – relationship of procurement function with suppliers – value added by procurement – role of procurement in securing plan deliverability

Keys Aspects of Asset Management that Ofgem Focuses on In the following paragraphs we highlight the key aspects of asset management to which Ofgem gives particular attention during investment plan reviews. These elements cover the contextual information, development requirements, investment justification, content and delivery of utility investment plans and underpinning asset management practices.

Context:

– Overall Asset Management Practices – the investment plan forms one part of the overall asset management framework. Consequently, across all of the regulated network businesses, Ofgem will closely examine the various asset management frameworks in order to establish confidence in the competence and maturity of asset management in each organization and thus the credibility of the submitted investment plans.

– Asset Data – this covers each of the primary asset types or categories, equipment volumes, age, asset condition, maintenance history/schedules, replacement costs, etc. Ofgem expects to see comprehensive data regarding the asset base for each company; much of which is requested provided via the BPQ. The more comprehensive, detailed and robust the data, the greater the confidence in asset management capabilities.

Development:

– Investment Plan Process – underpinning the investment plan is the process from which the plan was developed, detailed, costed and internally approved. This is a key area of focus for Ofgem as it provides assurance (or otherwise) regarding the credibility of the investment plans submitted for assessment for a price control period. Typically, Ofgem will be seeking evidence of a centralized, enduring investment planning


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process with appropriate governance, participation from senior officers and evidence of internal challenge.

Justification:

– Asset Health & Risk – of particular importance to Ofgem as the UK energy network asset base ages and nears end of nominal life, is the ability of network business to demonstrate a full understanding of the health (or condition) of its asset base and the associated asset specific risks (environmental damage, network operational failure, and danger to individuals). Here, Ofgem seeks the rationale for and evidence of asset replacement requirements rather than reliance on simplistic “end of life” anniversary models. It is also particularly important in the context of a logistical constraint on replacement activity to demonstrate an understanding of how to prioritize such asset replacement to minimize consequential asset related risks.

– KPIs/Output Measures – in addition to asset health and risk information, an increasingly strong area of focus for Ofgem is the development of Key Performance Indicators (KPIs) and standardized Output Measures to demonstrate the impact of investment on network performance (e.g., customer minutes lost (CML), customer incidents (CIs), network losses, carbon emissions, network availability, etc.). The aim is to ensure an improved understanding of overall network health and risk (to add to that of individual asset health and risks) The presence of such KPIs/output measures and the ability to link these to investments provides greater confidence to Ofgem of justification of investments ex-ante and greater ability of Ofgem to assess the impact of investments ex-post. The development of appropriate Output Measures is an evolving field in Great Britain’s network regulation.

Content:

– Standard Format of Presentation – To enable comparison with both peer companies and previous Price Control Review submissions, Ofgem seeks to ensure a standard format is applied in the presentation of the investment plans. This is essentially the role of the BPQ. More detail regarding the BPQ is provided later. However, the initial form of BPQ template issued by Ofgem for the ongoing DPCR5 process (i.e., review of Great Britain electricity distribution businesses for the regulatory period 2010/11-2014/15) and the accompanying documents providing


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guidance on BPQ completion and related commentary can be downloaded from Ofgem’s website29.

In Great Britain, Load Related Capital Expense (due to generation connection,; demand connections and resultant necessary network reinforcement/reconfigurations) and Non-Load Related Capital Expense (due to assets nearing end of life or failing) are reviewed as distinct high-level categories which are then broken down further to reflect the key component elements. For electricity networks, Non-Load Related Capital Expense high-level categories are typically – overhead lines, underground cables, switchgear, transformers, protection and control, and substation other (e.g., civils).

At a summary or component level (down to scheme by scheme for transmission), Ofgem seeks investment volumes and costs to be shown across the years of the price control (to indicate timing of investment and thus timing of volumes of assets installed and replaced and the resultant timing of costs incurred).

Data is always provided in spreadsheet form, via the BPQ submission, to enable Ofgem (and supporting consultants) to conduct additional analysis on submitted data. This is a key part of ensuring the burden on Ofgem is not unmanageable.

Delivery:

– Work Volumes and Procurement Efficiencies – a key area of scrutiny for Ofgem in recent price controls has been a review of the proposed work volumes within investment plans and thus: a) the ability of the network businesses to physically deliver the investment program (outage availability, manpower, equipment, etc.); and b) the effectiveness of the network businesses in procuring assets and turnkey scheme delivery. This relates to issues of credibility and efficiency where Ofgem scrutinizes if companies can actually deliver what has been proposed and whether costs are being minimized through economies of scale and related good practice procurement (commoditization, bulk procurement, options, etc.).

29 The BPQ tables, and guidance documents can be found at: http://www.ofgem.gov.uk/Pages/MoreInformation.aspx?docid=91&refer=Networks/ElecDist/PriceCntrls/DPCR5


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This section describes the information gathering process, whether internal or in a public forum, in relation to asset management practices, systems, tools (including software applications) as these apply to the network businesses (gas and electricity; transmission and distribution) that Ofgem regulates.

3.3.1 Formal Requirements – Price Control Reviews

Within the overall process Ofgem applies in conducting Price Control Reviews, a number of confidential and public means of information gathering are employed. While each is highlighted below, we represent them here and outline the role they perform:

BPQs (Confidential) – the primary mechanism for obtaining comprehensive detailed data and information in the first instance. For each Price Control Review, Ofgem will develop a specific BPQ for the network businesses to complete. The detailed assessment of investment plans will commence upon receipt of the BPQ submissions by the network businesses. In the current DPCR5 process, Ofgem has allowed the DNOs to submit an initial BPQ response (August 2008) followed by a final BPQ response (February 2009) in light of interim assessment and consequent feedback and guidance from Ofgem.

Bilateral meetings/workshops (confidential) – bilateral meetings operate at three levels as illustrated below:

Figure 30: Levels of Bilateral Meetings/Workshops

Tie Ofgem Network Business

1 Ofgem Authority/MD CEO

2 Ofgem Network Director Typically Regulation Director

3 Ofgem Functional Lead (Capex; Finance) – usually a Price Control Team lead too

Business functional lead (e.g., Capex; Finance) – usually an overall Price Control Team lead too

The bulk of the information gathering and related interaction on a day-to-day basis will be on the third tier following receipt of the BPQ information and this is where a number (5-15 depending on network business size) of extended meetings and workshops will take place to look at various aspects in depth (e.g., historical capital expense performance by LRE and NLRE), asset modeling, asset health/condition, generation and demand forecasts, procurement approach, and approach to environmental issues and capital expense projections by LRE and NLRE. In addition, there will be regular


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contact at the second tier where the key issues will be raised and this is where major observations and conclusions from detailed assessment will be escalated.

Finally there will be two to three opportunities spanning the Price Control Review process for top tier dialogue and this becomes particularly critical as the publication of Final Proposals approach – only the most critical and/or high-level aspects from assessment of the investment plans will be raised at this level as the focus is primarily on the “overall package”.

Written Q&A Process (Confidential) – a key component of the assessment process is a formal Q&A process which enables further clarifications and questions to be raised in the light of ongoing assessment of the BPQ material (and indeed previous Q&A responses). This Q&A process can easily see c.200 supplementary questions being raised specifically in relation to investment plans and supporting asset management practices

Site Visits (Confidential) – more applicable at a transmission level, a key part of information gathering as part of the “bottom-up” philosophy is conducting targeted site visits to ascertain and/or verify condition of assets and other indicated drivers of investment needs.

Multilateral Meetings (Confidential/Non-Confidential) – the use of multi-lateral meetings are a more recent feature of Price Control Reviews and seek to gather collective information on issues of either universal or comparative interest.

– As noted above, at one level these meetings may consist only of the network businesses and thus remain confidential. These meetings will tend to focus on various high level topics such as Environmental, Customer Service, Network and Financing.

– Other meetings involve wider stakeholder interests or a public forum. These latter meetings typically provide a lower level of detail than other forum and are used for gauging stakeholder priorities and degree of satisfaction with network business performance and objectives. These take two forms:

1) National forums for stakeholders – Ofgem establishes a representative sample of stakeholders covering different interests/perspectives to discuss and provide feedback on key/generic issues in relation to the relevant network utility businesses under review.


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2) Network utility forums for stakeholders – Ofgem requires each of the network utilities to conduct regular stakeholder events where they invite stakeholders within their network area to discuss and provide feedback on the network utility’s performance and future plans. At a distribution level, this effectively establishes a number of regional stakeholder forums and allows reflection of regional variances (e.g., the mix of stakeholders in London will vary strongly from those in Northern Scotland) and thus, their collective focus/prioritization on different aspects of network utility performance and future plans will vary. These utility run stakeholder events typically occur 1-2 times per year and take greater significance within Price Control Reviews, where Ofgem attends and takes notes of expressed views, etc., for consideration within the price control determination for each network utility.

Consultant Assessments (Confidential/Non-Confidential) – Ofgem utilizes a range of specialist expert consultants within Price Control Reviews. This includes using consultants to help assess investment plans. These consultants typically conduct comprehensive detailed assessments on behalf of Ofgem, advising on key issues for further evaluation with the network businesses. The associated consultant reports are usually confidential and shared bilaterally with the respective network business. However, sanitized versions are also made available for the benefit of wider stakeholders, and related material is inserted in Ofgem consultations and proposal documents.

Consultations (Non-Confidential) – These form a key part of the information gathering process in seeking to establish the ground rules and timetable of the review process, provide notification of the key issues and areas of focus, give early indications of observations and conclusions from assessments and opportunity for discussion of proposed recommendations for final decisions, in this case with respect to the degree of acceptance of the investment plans submitted under the BPQ (and thus the consequential determined revenue allowances for the price control period). The process chart earlier in this document has previously highlighted the nature and timing of consultations for DPCR5.

3.3.2 Formal Requirements – Annual Regulatory Reporting

In recent years, Ofgem has sought to move from a purely periodic 5 year review of the network businesses to an environment where comprehensive standardized information is provided on an annual basis regarding the performance of the network businesses against their regulatory allowances. This process is largely confidential but some aspects are made public,


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such as Quality of Service performance, which is collated and issued as a stand alone document.

Ofgem first introduced the annual reporting requirement on electricity distribution businesses as part of DPCR4 (settled 2004); followed by implementation of a similar annual reporting requirement on transmission network businesses (gas and electricity) in TPCR4 (settled 2006) and finally on gas distribution network businesses in GDPCR4 (settled 2007).

The reporting requirement is essentially the annual completion of detailed spreadsheets aligned to the price control’s BPQ structure. It seeks to capture all of the key data indicating performance of the network businesses on a year-by-year basis. This annual process allows a picture to develop of how network businesses are performing within a price control period against: a) what was submitted to Ofgem for approval in their BPQ submissions; and b) what Ofgem ultimately set as their view of necessary activities and what it used to derive allowed revenue allowances for the network businesses.

With regard to investment plans, as an example for distribution networks, this annual regulatory reporting process will collect detailed annual data on:

Overall capital expense by asset category; – Tier 1: load related vs. non-load related – Tier 2: or electricity distribution this includes overhead lines; poles;

towers; underground cables; transformers; switchgear, etc. – Tier 3: voltage level.

Asset volumes and cost of replacements, additions and removals from the networks (by type) for each the primary purpose is to be indicated;

Volume and costs of assets refurbished;

Details of load related and non-load related capital expense schemes (in case of distribution, the N largest for each) which are required to justify replacement need and program (i.e., timing of works/cost);

Asset age profile by asset type (and voltage) to provide useful insights regarding the remaining useful asset lives; and

Various network operating and performance metrics including: – Quality of service30

o Customer Numbers o CIs and CMLs (excluding exceptional events)

– Network activity indicators 30 As an example, the latest Ofgem Quality of Service Report for the 14 GB electricity DNOs can be found at: http://www.ofgem.gov.uk/Networks/ElecDist/QualofServ/QoSIncent/Documents1/2007.08%20Quality%20of%20Service%20Report%20v2.pdf


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o Number of Connections o Total Connected Generation o Demands o Units Distributed o Losses

– System Parameters o Distribution Circuit Length – Overhead (km) o Distribution Circuit Length - Underground (km) o Number of Substations and Switching Stations o Number of substations >80% load o For relevant substations - Timing of when reach 100% capacity

The above gives an example of the level of detail which Ofgem requires under regulatory reporting. A further indication is given by the fact that an annual guidance report is required on how to complete the regulatory reporting package each year; often comprising in excess of 100 pages, with the reporting pack (i.e., spreadsheet) themselves comprising in excess of 30 detailed tables and 15 supporting documentary information items.

3.3.3 Other Information Gathering

In addition to the standardized reporting requirements for network businesses as part of the 5-yearly Price Control Reviews and the annual regulatory reporting process, Ofgem also gathers information in relation to asset management practices, systems and tools adopted more widely by comparative companies internationally (e.g., in Europe) and comparative industry sectors (e.g., rail, aviation) through other mechanisms and forum.

For example, Ofgem is a member of, and currently chairman of ERGEG (European Regulator’s Group for Electricity and Gas). This body provides advice to the EU but also seeks to share knowledge and best practice in the regulation of national electricity and gas markets. As such they seek to compare, for example, the approaches to asset management adopted by network businesses within each of the markets and to benchmark performance (subject to recognition of differentiating contextual factors such as design standards).

Another example is that Ofgem has commissioned advice about asset management related output measures adopted in other industry sectors such as rail or aviation, which can be meaningfully translated into equivalent output measures for electricity and gas network businesses.


This section describes key asset management principles and practices that Ofgem explicitly consider, expect or require to be followed by electricity and natural gas distributors or transmitters in their jurisdiction.


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3.4.1 Adoption of PAS 55 Aligned Asset Management Practices

In the last few years, Ofgem has promoted the development and adoption of robust asset management practices. In particular, Ofgem has been a driving force behind the promotion and development of the PAS 55 asset management framework. The PAS 55 asset management framework is increasingly being adopted by infrastructure companies in different industry sectors worldwide. While Ofgem has not stipulated that Great Britain network businesses become PAS 55 certified by an independent body, it has strongly encouraged Great Britain transmission and distribution businesses to implement asset management policies, frameworks and practices in line with PAS 55. Consequently, most Great Britain network businesses now have PAS 55 certified Asset Management Systems and indeed, National Grid, which owns both national gas and electricity transmission networks as well as some regional gas distribution networks, was the first utility and second company worldwide to be formally accredited with PAS 55 status.

There remains a strong expectation that all Great Britain network businesses covering gas and electricity and transmission and distribution networks should develop and apply some form of well documented asset management framework and associated practices. This expectation shapes Ofgem’s attitude to its assessment of investment plans submitted by the network businesses. To be specific, those network businesses which can demonstrate strong asset management practices (aligned with indicated policies, i.e., do what they say) will receive due credit from Ofgem and will also find the regulatory scrutiny process less challenging as a consequence of the availability of comprehensive asset information.

3.4.2 Adoption of Explicit Output Measures

A further explicit asset management requirement which Ofgem has begun to implement across all of the network businesses it regulates is the development and reporting of output measures by the network businesses relating to network performance, asset condition, and risk.

Recently, the three electricity transmission companies published their proposals for the output measures, which could be applied within both their general asset management framework and associated practices, but also in the setting and variation of their price control period revenue allowances, i.e., how these could be linked to business costs and thus revenue needs.

Ofgem’s stated main objectives for developing transmission network output measures are to enable it to:

Assess effective asset management: i.e., to identify measures that will allow Ofgem to better assess the efficiency of historic and forecast capital expense with a focus on the replacement and the maintenance of network assets to ensure that the actual forecast network risk profile is within acceptable bounds.


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Understand network performance: if possible, to improve the measures of network performance that impact consumers which have a clearer interaction with network investment.

Develop comparative analysis and sharper incentives: the development of output measures should enable Ofgem to compare the performance of transmission and distribution companies. The benefits of comparative analysis have already been demonstrated in gas and electricity distribution and in other sectors such as water. In addition, the measures may help Ofgem to target incentives on specific aspects of performance.

Provide greater information to network users: developing output measures should also reveal more information about network capability at present and in the future. This will inform users’ decisions regarding network access or capacity arrangements.

The areas in which Ofgem is seeking to identify and apply output measures and to enable evaluation of, are:

Network asset condition; Network risk; Network performance; and Network capability.

The potential output measures to be adopted are currently the subject of an Ofgem consultation but the table below indicates the transmission network businesses’ proposals for consideration.

Figure 31: Proposed Output Measures put forward by GB Network Utilities

Source: Ofgem


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Ofgem has formally indicated in an open letter on DPCR5 process published on 6 November 200831 that it will apply a similar approach for distribution, seeking some form of output measure adoption (trial period or explicitly driving revenues) by the DNOs under DPCR5. Previous price control settlements have entailed DNOs having to deliver relatively little by way of formal outputs beyond the general requirement to meet license and statutory requirements.

Ofgem has incentivized certain types of outputs through specific mechanisms, such as interruptions and losses, but these do not encompass the full range of outcomes that result from DNOs’ network investment and operational activities. As a result Ofgem seeks to reduce ambiguity regarding the nature of the overall price control settlement.

Thus, for DPCR5, Ofgem has decided that the price control settlement should allow DNOs to earn regulated revenues in exchange for them agreeing to deliver a defined set of outputs in a sustainable manner and meet all license and statutory requirements. This is in contrast to a settlement which involves the DNOs simply managing expenditure within their allowances or delivering a fixed volume of work such as a certain number of kilometers of overhead line and transformers replaced.

In its Open Letter, Ofgem indicated that DPCR5 output measures will become a key feature of the price control arrangements for a number of reasons:

Should be the basis of DNOs’ management of the network; Integral to the assessment of DNOs’ historical and forecast costs; and Ensuring that DNOs deliver – value for money.

Thus, in the Open Letter, Ofgem stated it is seeking to work with the DNOs to agree output measures and associated targets for DPCR5 as an integral part of the price control process. This will be done on a company specific basis based on the systems and information that is available in each company, although in some areas such as interruptions common metrics will continue across the industry. Furthermore, Ofgem has stated that they are looking for DNOs to commit to a DNO specific package of measures as part of the price control settlement including for example:

31 This open letter can be found at http://www.ofgem.gov.uk/Networks/ElecDist/PriceCntrls/DPCR5/Documents1/Open%20letter%20on%20%20DPCR5%20process%20051108.pdf


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Figure 32: Ofgem’s Indicated Examples of Potential Output Measures for GB DNOs

Overall customer performance – Number and duration of interruptions

– Customer satisfaction with the DNO

Load related spend – Connection or customer driver – For highly loaded substations, number of

customers at risk, potential time at risk, extent of load growth

– Asset utilization Non load related spend – Fault rates

– Indices for the condition of the network – Modeled percentage remaining useful asset life

Source: Ofgem

In contrast to the implicit indications Ofgem has provided regarding the influence of PAS 55 aligned asset management practices on its view of network business investment plans, Ofgem stated that under DPCR5, those DNOs who do not demonstrate or provide output measures, will be subject to much more intense regulatory scrutiny in the assessment of their investment plans.



Ofgem is the Office of the Gas & Electricity Markets which regulates the electricity (and gas) industries in Great Britain. Ofgem is governed by the Gas & Electricity Markets Authority and its powers are provided under the Gas Act 1986 and the Electricity Act 1989, as amended most recently by the Utilities Act 2000.

Ofgem has a statutory duty under Section 3A of the Electricity Act 1989 to protect the interests of gas and electricity customers. Ofgem exercises its functions by issuing licenses that have enforceable conditions (standard license conditions) and can also enforce compliance with certain statutory provisions.

Ofgem has two primary duties, which are to:

1) To promote competition by creating the conditions which allow companies to compete fairly and customers to make informed choices; and

2) To regulate areas of business where competition is not effective. This is mostly achieved by means of price controls and the monitoring of formal standards, to ensure value for money and good service.

It is this latter aspect which is relevant in the regulation of network utility investment plans. The scope of the price control has developed over time in response to changes within the


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industry and the development of competition. Transmission and distribution price reviews are carried out every 5 years.


In Great Britain, the transmission and distribution systems for gas and electricity are monopoly businesses (at a national level for transmission and a regional level for distribution) and are regulated by price controls. The intention of price control is to protect customers where there is a lack of competition, and to encourage efficiency by determining inflation-limited price caps.

The basis of Ofgem’s price controls is an RPI-X formula that controls the average revenue earned by the regulated businesses. The RPI-X price control takes the retail price index - rate of inflation - as its benchmark and subtracts X - an efficiency factor - from it. The X factor is used to reflect expected efficiency gains and investment requirements. For example, when RPI is running at 3% and X is 2%, a company would be allowed to increase prices by no more than 1% per annum.



Transmission networks play a central role in the electricity system. Maintaining the balance between supply and demand is a vital task which touches every aspect of electricity supply. Under the terms of their transmission licenses, the transmission companies are required to develop, maintain and operate an efficient and economical system of electricity and to facilitate competition in generation and supply.


As indicated above, there are 14 Distribution Network Operators (DNOs) covering 14 regional DSAs in Great Britain who are responsible for owning and operating electricity distribution networks. While these 14 DNOs are owned by seven companies there is a separate distribution license for each DNO/DSA. These are granted by Ofgem to the owners’ of the DNOs, for the provision of distribution network services within a specified DSA.

Under the license, the DNO owns and operates the local electricity distribution system within this authorized area. Therefore, DNOs have specific obligations and responsibilities in relation to defined service areas of the network. Specifically, under the terms of their DSA licenses, DNOs have statutory duties to develop and maintain an efficient, coordinated, and economical system of distribution and facilitate competition in generation and supply. They have a duty to connect any customer who requires a supply. DNOs are obliged to meet minimum standards of performance related to distribution services, which are set by Ofgem. These can vary by DNO/DSA even within common ownership.


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Gas Transmission

National Grid is the sole license holder for owning and operating the gas transmission network in Great Britain.

Gas Distribution

There are four gas distribution license holders covering eight gas distribution areas overlaying the 12 historic LDZs.



There is no explicit regulatory guidance regarding the specific preparation of asset management plans underlying a regulatory submission as part of a Price Control Review.

Nonetheless, in recent years as the assets comprising the Great Britain electricity and gas networks infrastructure has begun to increasingly near end of life and consequential asset replacement investment expenditure has begun to rise strongly, Ofgem has placed an increasing emphasis on the quality of the utilities’ asset management practices and investment planning processes which they operate and which underpin their regulatory submission. In particular, in the last 5 years, Ofgem has encouraged adoption of practices consistent with the emergent PAS 55 asset management standard and more recently the adoption of output measures to demonstrate the impact of activities and investments on utility assets and their network as a whole in terms of performance and risk.

While Ofgem did not explicitly impose a PAS 55 requirement on utilities it did implicitly favor those companies who were able to demonstrate asset management practices accredited under PAS 55 or demonstrably consistent with PAS 55. This took the form of greater credence being given to company forecasts and greater likelihood of regulatory settlements for a price control being closer to the initial submission by the relevant utility.

While Ofgem continues to put strong emphasis on the presence of asset management practices aligned to or accredited under PAS 55 in the current Great Britain electricity Distribution Price Control Review (DPCR5), Ofgem has added an explicit emphasis on output measures as being a key feature they expect to see presented by the 14 electricity DNOs.

Ofgem’s emerging approach on output measures is explicit, in contrast to the implicit indications Ofgem has previously provided regarding the influence of PAS 55 aligned asset management practices on its view of network business investment plans. Specifically, it has explicitly indicated that under its conducting of DPCR5, those DNOs who do not satisfactorily demonstrate or provide proposed output measures to Ofgem will be subject to much more intense and less favorable regulatory scrutiny in the assessment of their investment plans; amongst other things.


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As part of DPCR5, Ofgem is looking for DNOs to commit to a company specific package of output measures that reflect what the DNO already measures internally. They have indicated they will not set out their own views on the level of risk that DNO plans will generate, as this is for companies to decide. However, Ofgem has clearly indicated that they will want to be reassured that the output measures are consistent with the capital expense plan each DNO is putting forward.

In an Open Letter on output measures, Ofgem very recently outlined two different types of deal that DNOs could expect, based on whether Ofgem determines that as part of their regulatory submissions they provide well-defined outputs (Type 1) or limited outputs (Type 2). Ofgem has indicated they expect all DNOs to aim for a Type 1 settlement (even if Ofgem subsequently determines a Type 2 settlement is more appropriate for one or more DNOs).

An overview of the nature of the regulatory settlements (and their derivation) under each of the Type 1 and Type 2 conditions as provided by Ofgem in its Open Letter are outlined below.

Figure 33: Overview of the Nature of Regulatory Settlements

Type 1 Settlement – Well Defined Outputs Type 2 Settlement – Limited Outputs

Common base cost of capital

Challenge to DNO forecasts

Tightly defined outputs which are measureable and verifiable

High powered incentive scheme

Easier to reach high returns based on verifiable performance against costs and outputs

Limited scrutiny of under-spend as long as output measures are met

Extra challenge to forecasts

More limited output information

Greater use of CI, CML and fault rate

Use of some input measures

Lower powered incentive scheme

More difficult to obtain higher returns

More intrusive scrutiny of any under-spend against capex allowances (and even scrutiny if no under-spend)

Ex-post review of capex (three pots treatment)

Common CI and CML incentive rates (Ofgem will consult on this in December) and common standards of performance

Source: Ofgem


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Apart from the linkage to output measures as discussed above, there is no explicit regulatory guidance regarding the specific preparation of investment plans to be submitted as part of a Price Control Review, i.e., how they are formulated and the content which they contain.

However, in an approach which they have adopted for a number of price controls, Ofgem provided a Business Plan Questionnaire (BPQ) template for each regulated entity to complete during the relevant Price Control Review process. By providing this BPQ, Ofgem specifies the way in which the content of a utility’s investment plans and underlying asset management plans are presented. This is for two reasons:

1) To ensure capture of all the data and information which Ofgem deems necessary in the first instance to begin to assess the merits of the utility’s submitted investment plan and related engineering activities operating expense plan (and thus together with other elements the consequential price control revenue allowance); and

2) To enable comparative and benchmarking analysis between different utilities; typically the group being assessed within a specific price control (e.g., the 14 Great Britain electricity distribution companies) but also across Great Britain utilities (e.g., transmission or perhaps comparable other sectors such as water and rail) and in some aspects, potentially comparable international utilities.

An overview of the content (i.e., data sheets) of a BPQ is provided below as taken from the current Ofgem review of the Great Britain electricity distribution companies, the initial form of the BPQ template issued by Ofgem for the ongoing DPCR5 process (i.e., review of Great Britain electricity distribution businesses for the regulatory period 2010/11-2014/15) and the accompanying documents providing guidance on BPQ completion and related commentary can be downloaded from Ofgem’s website32.

32 The BPQ tables, and guidance documents can be found at: http://www.ofgem.gov.uk/Pages/MoreInformation.aspx?docid=91&refer=Networks/ElecDist/PriceCntrls/DPCR5


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Figure 34: Summary of DPCR5 BPQ Tables Issued by Ofgem for Completion by all GB DNOs Table DescriptionT1 - Summary Network costs forecasts summary, DPCR4 and DPCR5 comparison.T2 - Total network costs Network costs overview by building block and by year for DPCR4 and DPCR5.T3 - Total business costs Total business costs summary. [to be developed]

LR1 - Demand Forecast trends in maximum demand and units distributed, forecasts of customer specific connection data and expenditure.

LR2 - GenerationForecast of distributed generation (DG) connection by type, number of units, MW and associated expenditure. Forecast of expenditure on DG by voltage level.

LR3 - DiversionsForecast of number of diversions, length, expenditure and customer contributions.

LR4 - General reinforcement Forecast expenditure requirements to comply with ER P2/6.LR5 - System utilisation Forecast of changes in substation utilisation parameters produced by forecast level

of expenditure. LR6 - Fault levels Forecast expenditure due to fault level issues and forecast effects of this level of

expenditure on system measures of fault level issues.LR7 - DNO discretionary Expenditure which the does not fit into the other building blocks.

NL1 - Condition based expenditure Forecast condition based expenditure split by fault and non fault.NL2 - Condition based QoS Forecast baseline QoS output measures and fault rates delivered by condition

based expenditureNL3 - Condition based volume Forecast volume of condition based replacement by asset type.NL4 - Remaining useful life Forecast change in percentage of asset base with remaining life expiring within 5

years produced by forecast level of expenditure.NL5 - QoS (IIS) Forecast quality of service projects and levels of expenditure targeting IIS output

improvements.NL6 - QoS (non IIS) Forecast quality of service projects and levels of expenditure targeting non IIS

improvements.NL7 - Major sys risks Forecast expenditure requirements to alleviate flooding issues, and the effect of

this level of expenditure on number of substations at risk. Forecast expenditure on CBDs.

NL8 - Operational IT & telecoms Forecast expenditure on operational IT and telecoms including projects required due to BT 21st Century.

NL9 - Legal & safety Forecast expenditure due to legal requirements, including ESQCR.NL10 - Environmental Forecast expenditure due to environmental drivers.

NOC1 - I&M Forecast expenditure on inspections and maintenance by voltage level and asset category and details of inspection and maintenance frequency.

NOC2 - Fault costs Forecast fault costs, non QoS faults and numbers of unplanned incidents.NOC3 - Tree cutting Forecast tree cutting expenditure, overhead network and tree coverage related

parameters and details of tree cutting cycles.NOC4 - Other network costs Network operating costs not included elsewhere

E1 - Engineering indirects Forecast expenditure on Engineering indirects by high level direct cost category and proportion of total direct cost expenditure.

C1 - Cost increase Details of above RPI cost increases.C2 - Unit costs Details of new build and replacement unit costs and associated engineering

overheads.

Source: Ofgem

To highlight what these BPQ tables look like we provide two examples over the next two pages:

1) The template High Level Table T2 providing an overview of the Total Network Costs; and

2) The template Detailed Level Table NL3 providing an overview of the Forecast Volume of Condition Based Asset Replacement by Type of Asset.


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Figure 35: DPCR5 BPQ Table NL2 – Total Network Costs (Source: Ofgem)

August Forecast Business Plan DPCR5 DNO entered on version control sheet

T2 - Totals Network Costs

Load related investment

2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12 2012/13 2013/14 2014/015 Actuals total (3 years)

Forecast total (2 years) Total DPCR4 Total DPCR5 Percentage

Change Customer specific (gross)

Demand 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Generation 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Diversions 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0

Total 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Customer specific (net)

Demand 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Generation 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Diversions 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0

Total 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 General reinforcement

P2/6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Fault Levels 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0

Total 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 DNO discretionary 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Total 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Non load related investment 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12 2012/13 2013/14 2014/015 Actuals total

(3 years)Forecast total

(2 years) Total DPCR4 Total DPCR5 Percentage Change

Asset replacement 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Quality of supply (IIS) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Quality of supply (non IIS) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Major system risks 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Operational IT and telecoms 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Enviromental 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Legal & safety 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Total 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Network operating costs 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12 2012/13 2013/14 2014/015 Actuals total

(3 years)Forecast total

(2 years) Total DPCR4 Total DPCR5 Percentage Change

Inspections and maintenance 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Fault repairs and restoration 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Tree cutting 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Other Network costs 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 Total 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0

DPCR 4 DPCR 5 DPCR 4 DPCR 5

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Figure 36: DPCR5 BPQ Table NL3 – Forecast Volume of Condition Based Asset Replacement

August Forecast Business Plan DPCR5 DNO entered on version control sheetNL3 - Condition based volume

Condition based asset register movement

Asset register movement Asset management

Asset categories Asset Register Assets removed Assets installed

Total as at start DPCR5 based

only on condition replacement only Assets removed Assets installed

Total based on condition

replacementProgramme of replacement

Manage to failure

01 April 2008 08/09 & 09/10 08/09 & 09/10 01 April 2010 DPCR5 DPCR5 1 April '15 Y/N Y/NLV Network

Overhead lines - ConductorLV Main (OHL) - - -LV Service (OHL) - - -

Overhead lines - SupportLV Support - - -

Underground cablesLV Main (UG Consac) - - -LV Main (UG Plastic) - - -LV Main (UG Paper) - - -LV Service (UG) - - -

Switchgear LV Pillar (ID) - - -LV Pillar (OD) - - -LV Board (WM) - - -LV UGB - - -LV Fuses (PM) - - -LV Fuses (TM) - - -

HV networkOverhead lines - Conductor

6.6/11 kV OHL (Open) - - -6.6/11 kV OHL (Covered) - - -20 kV OHL (Open) - - -20 kV OHL (Covered) - - -

Overhead lines - Support6.6/11 kV Support - - -20 kV Support - - -

Underground cables (kms)6.6/11kV UG Cable - - -20kV UG Cable - - -

Submarine cables (kms)HV Sub Cable - - -

Switchgear 6.6/11 kV CB (PM) - - -6.6/11 kV CB (GM) - - -6.6/11 kV Switch (PM) - - -6.6/11 kV Switch (GM) - - -6.6/11 kV RMU - - -6.6/11 kV Switchgear - Other (PM) - - -6.6/11 kV Switchgear - Other (GM) - - -20 kV CB (PM) - - -20 kV CB (GM) - - -20 kV Switch (PM) - - -20 kV Switch (GM) - - -20 kV RMU - - -20 kV Switchgear - Other (PM) - - -20 kV Switchgear - Other (GM) - - -

Transformers 6.6/11 kV Transformer (PM) - - -6.6/11 kV Transformer (GM) - - -20 kV Transformer (PM) - - -20 kV Transformer (GM) - - -

EHV NetworkOverhead lines - Conductor

33kV OHL (Pole Line) - - -33kV OHL (Tower Line) - - -66kV OHL (Pole Line) - - -66kV OHL (Tower Line) - - -

Overhead lines - Support33kV Pole - - -33kV Tower - - -66kV Pole - - -

66kV Tower - - -

Underground cables (kms)33kV UG Cable (Non Pressurised) - - -33kV UG Cable (Oil) - - -33kV UG Cable (Gas) - - -66kV UG Cable (Non Pressurised) - - -66kV UG Cable (Oil) - - -66kV UG Cable (Gas) - - -

Submarine cables (kms)EHV Sub Cable - - -

Switchgear 33 KV CB (ID) - - -33 kV CB (OD) - - -33 kV Switch (GM) - - -33 kV Switch (PM) - - -33 kV RMU - - -33 kV Switchgear - Other - - -66 KV CB (ID & OD) - - -66 KV Switchgear - Other - - -

Transformers 33 kV Transformer (PM) - - -33 kV Transformer (GM) - - -33 kV AuxiliaryTransfomer - - -66 kV Transformer - - -66 kV AuxiliaryTransfomer - - -

132kV NetworkOverhead lines - Conductor

132kV OHL Conductor (Pole Line) - - -132kV OHL Conductor (Tower Line) - - -

Overhead lines - Support132kV Pole - - -132kV Tower - - -132kV Fittings (Tower Line) - - -

Underground cables (kms)132kV UG Cable (Non Pressurised) - - -132kV UG Cable (Oil) - - -132kV UG Cable (Gas) - - -

Submarine cables (kms)132 kV Sub Cable - - -

Switchgear 132 kV CB (ID & OD) - - -132 kV Switchgear (other) - - -

Transformers 132 kV Transformer - - -132 kV AuxiliaryTransfomer - - -

Tele-control / SCADAPrimary substation

132 kV/EHV RTU (PM) - - -132 kV/EHV RTU (GM) - - -

Secondary substationHV RTU (PM) - - -HV RTU (GM) - - -

Volume OHL refurbishment

Asset categories Kms refurbished Kms refurbishedDPCR5

refurbishment 08/09 & 09/10 DPCR5 cycle (yrs)

LV NetworkRefurbishmentStructures onlyFull rebuildUndergrounding

HV NetworkRefurbishmentStructures onlyFull rebuildUndergrounding

EHV NetworkRefurbishmentStructures onlyFull rebuildUndergrounding

132kV NetworkRefurbishmentStructures onlyFull rebuildUndergrounding

Navigate

(Source: Ofgem)


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It can be seen from the above example tables alone that the BPQ is very comprehensive and deep. It is review of this BPQ data and information which forms the basis of Ofgem’s detailed Price Control Review assessment process and drives the subsequent interactions (meetings, workshops, Q&A, etc.), which ultimately lead to the final regulatory settlement for each of the network utilities subject to review.


It is evident from the material above that while review of investment plans has always been a key element of network utility regulation since they were privatized, the increasingly strong focus on asset management practices and performance has been an emergent theme in recent years and a central aspect of Ofgem’s focus in its future regulation of network utilities in Great Britain. Some of the reasons for this (lessons learned) and elements of future focus of Ofgem on asset management are outlined below.

Lessons Learned

The current and future focus on asset management by Ofgem reflects a number of lessons learned from its regulation of network utilities to date:

Loss of knowledge: When network utilities were first privatized as part of an unbundled liberalized energy market, a clear focus was on introducing efficiencies to drive down costs. Consequently, a key focus was on reducing operating expense and inevitably, as a major component of this, a reduction in staff. In most cases this reduction was achieved through reorganization and site consolidations by loss of older staff. Many of the staff retained up to 40 years of detailed experience and knowledge which was not systematically captured or recorded and thus many elements of intangible data and information was lost. This loss/lack of detailed knowledge of the asset base became of increasing importance as the assets aged and decisions need to be made on asset replacement priorities. It has been recognized by Ofgem and the utilities that such information has to be systematically captured (and used) by the network utilities and not vested in the minds/memories of individual staff.

Aging assets - need to manage asset replacement: As mentioned above and previously, the UK network assets in general are nearing nominal end of life and were put in place over relatively short timeframes in the 1960’s (for electricity) and the 1970’s (for gas). Thus, there is an inevitable need to increase levels of asset replacement, but in a more efficient network regime (i.e., higher average utilization of network assets). There is not the same ability too install such large volumes of new equipment and thus, there is a need to manage the asset replacement wave (or “wall” as some have called it) effectively. To do so there needs to be comprehensive, detailed, and accurate asset information, not just for the utilities’ themselves, but for Ofgem to be able to assess what is a reasonable approach and associated expenditure to ensure appropriate asset/network health, performance and risk.


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Regulatory drivers to under-invest: In the early years of privatization, a major focus of Ofgem’s predecessors (Offer and Ofgas) was to promote competition. From a network perspective the primary investment driver was associated with load related drivers, such as change in generation, and source of gas supplies. Consequently, there was less focus placed on asset management and given ever decreasing regulated revenue allowances, network utilities squeezed asset management related investment to ensure they obtained the best financial outcomes in outturn under their regulatory settlements. Ofgem has recognized that regulated revenues now need to increase and/or flex to accommodate genuine asset management needs to maintain asset/ network health, performance and risk.

Ownership incentives to under-invest: The incentive to under-invest from the form of price control to some extent led to under-investment in some areas of asset replacement, but particularly asset inspections, condition assessment and maintenance activities. This was further exacerbated, especially at a distribution level, by the various acquisitions and takeovers of the original network utilities by new owners/investors who sought to maximize their financial returns. The consequence of this under-investment for various networks has been deteriorating asset health, performance, and safety, which only serve to worsen the asset replacement wave/wall to be addressed in the next 10-15 years. Ofgem has recognized this and the need to ensure that changes of ownership or organizational structures do not inappropriately impact on asset management and related capital and operating expense to ensure acceptable asset/network health, performance and risks.

Areas of Future Focus

Ofgem’s area of future focus is based on their experience and observations gathered since Great Britain network utilities were first privatized in 1990. However, Ofgem has been principally driven, in the context of an aging asset base (towards end of life), by the realization of the issues identified above and the observed consequences in terms of asset/network health, performance and risk. Thus, in recent years, Ofgem has focused their attention on the development of strong asset management practices (and associated investment plans) by the network utilities through a number of initiatives and regulatory incentives. These primarily include, as discussed above, PAS 55 compliance (formal or otherwise) and use of KPIs/output measures.

Going forward it is clear that Ofgem’s future focus for regulation/incentivization of asset management practices is as follows:

Consolidation of best practice asset management: Ofgem will continue to seek further development and improvement of the asset management practices of the network utilities Having “strongly” encouraged network utilities to adopt practices consistent with (and preferably accredited by) PAS 55, Ofgem will seek widespread adoption of “best practice” processes, tools and techniques by the network utilities and for them to continuously seek to improve.


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Putting asset management on CEO agenda: Ofgem is keen to ensure that previous “light” treatment of asset management by network utility executive management and owners is avoided. In particular, Ofgem will seek to ensure that financial objectives do not inappropriately override asset management considerations such that there is an inappropriate impact on asset/network health, performance and/or risk. In short, Ofgem wants to ensure asset management is a key item on the agenda of any network utility CEO in business planning.

Fully understanding asset/network health, performance and risk (KPIs): Ofgem believes that many Great Britain network utilities do not yet have a sufficiently good understanding of the health of theirs assets and/or networks, the performance of their network and, in particular, the risk (likelihood and/or consequence) they face as a result of network investment (and operating expense) decisions. Thus, they are clearly focused on ensuring network utilities will develop such understanding especially in the area of risk and furthermore to develop and use KPIs and output measures to be able to quantify their level of asset/network health, performance and risk as best as possible.

Use of KPI’s/output measures and linkage to revenues/capital expense: In the current network context, Ofgem is being asked to determine whether requested large increases in capital expense and operating expenses by network utilities is appropriate. Thus, they are very keen to establish output measures which demonstrate tangible outcomes for the regulated revenues (specifically the underlying capital expense) granted. Furthermore, a prime focus of Ofgem going forward is that there is an explicit linkage between the monies that the network utilities seek and spend versus their consequent asset/network health, performance and risk. This allows Ofgem to move further away from traditional scrutiny of investment plans and subsequent outturn investment versus that proposed at the start of a price control period. Specifically, it allows them to demonstrate value for money in an increasing spend climate by simply linking revenues to appropriate performance measures and allowing utilities to invest as they see fit to seek to meet their agreed targets for these performance measures. Such explicit linkage between revenues and output measures is being considered for the Great Britain electricity DNOs under the current DPCR5 process and is expected to be introduced in some form for DPCR5 – though a pure mechanistic approach is thought unlikely until at least DPCR6.

Appendix D: New Zealand

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4. Appendix D: New Zealand Background

New Zealand is a relatively small electricity market with less than 2 million customers. It has been liberalized for many years with separation between generation, transmission, retail and distribution and supply. There is strong vertical integration between the generation and retail parts of the industry, but this integration is restricted between distribution and generation and prohibited between distribution and retail sectors.

Regulation of the electricity sector is split between the Electricity Commission and the Commerce Commission. The Electricity Commission is responsible for the regulation of the wholesale and retail markets in line with the Electricity Act, whereas the Commerce Commission is responsible for the regulation of the distribution business. Unusually, the responsibility for regulation of the transmission business is split between the Electricity Commission and the Commerce Commission. The Electricity Commission tends to approve investment for large-scale grid reinforcements and enhancements, whereas the Commerce Commission sets thresholds for the remaining capital allowances and operating expenditures.

The Commerce Commission is also responsible for the regulation of the Gas networks. The networks only exist on the North Island and supplies domestic customers as well as major users, such as generation. Relatively light-handed regulation has been applied to most gas business in the past, but this has changed recently with formal controls being applied to two of the gas businesses.

In 2008, there were some major amendments to the Commerce Act, which governs how electricity lines and gas pipeline businesses are regulated. The implications of these upcoming changes to the regulatory structure will be a major part of this analysis.



Electricity

In New Zealand, there is one Transmission company (Transpower) responsible for the electricity Transmission network in both the North and South Island.

There are 29 Distribution companies (known an Electricity Lines Businesses) in New Zealand and these are listed in the table below.


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Figure 37: Electricity Distribution Businesses in New Zealand

Source: Regulatory Provision of the Commerce Act 1986 – Discussion Paper 19 Dec 2008

A map showing the location of each of the distribution companies is shown in the following section. It is worth noting that there is a considerable disparity in size with Vector (before the sale of part of the network in 2008) having 660,000 end users compared to the 4,000 that are the responsibility of Buller Electricity.

Gas

There are two gas transmission systems in New Zealand, which are the NGC system and the Maui Pipeline. The NGC system33 was developed first to serve the Kapuni field and breaks down into the following pipelines:

Kapuni to Wellington pipeline (South); Kapuni to Huntly pipeline (Central); Gisboure Pipeline (Bay of Plenty); and Northland Pipeline (North).

Since the discovery of the Maui field and the additional transmission line some of these pipelines no longer operate at full capacity.

33 Ownership has subsequently been transferred to Vector.


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The Maui pipeline runs for Oaonnui to the Huntly Power stations and is operated as part of the Maui gas supply system, although it is now an open access pipeline. The Maui pipeline is significantly larger than the NGC pipeline in terms of nominal bore.

Distribution businesses only exist in the North Island34. The major distribution companies are:

Vector – covering Auckland; NGC (now owned by Vector) – covering Hamilton, Mt. Maunganui, Tauranga and

Gisbourne; Powerco – covering Taranki, Wellington, Hutt Valley, Porirua, Manawatu and

Hawke’s Bay; and Wanganui Gas (called GasNet) – covering Wanganui and Marton.

In addition, Nova Gas has constructed pipelines that bypass those of the incumbent distributors and provide gas to customers in Wellington, Poirua, the Hutt Valley, Hastings, Hewara, Papakura and Manakau City.



Transpower has responsibility for the entire region and the interconnection between the two islands. An overview of the extent of the lines is shown in the diagram below.

34 There are 2 small LPG reticulation networks in the Christchurch and Queenstown CBDs, but these have been ignored for the purposes of this analysis.


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Figure 38: Map of the New Zealand National Grid

Source: Transpower Briefing to the Incoming Government – September 2008


The map below shows the location of the network companies that exist in the two island of New Zealand and comes from the Transpower. The map only contains 28 rather than 29 Distribution companies listed by the Commission. This difference is due to the inclusion of PowerNet, which includes the businesses of Electricity Invercargill and The Power Company listed by the Commission. In addition, it should be noted that Vector sold their old UnitedNetworks business in July 2008, which became Wellington Energy. This business is shown at the bottom of the North Island.


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Figure 39: New Zealand Electricity Distribution Businesses

Source: Transpower

Gas

An overview of the gas pipelines in New Zealand are shown in the diagram below. It is interesting to note the number of competing networks that Nova Gas has developed.


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Figure 40: Gas Pipelines Companies in New Zealand

Source: New Zealand Gas Matters October 2006

4.1.3 Key Technical and Financial Statistics


The transmission network consists of 11,800 kilometers of high voltage transmission lines and 178 substations and switchyards. It has assets in all 86 regional, district, and city councils in New Zealand. Around 40,000 GWh are annually generated and transmitted across the transmission network. The high-voltage direct current (HVDC) link between the North and South Islands includes 40 kilometers of submarine cables under the Cook Strait and two converter stations. The company has moved from a period of low investment to a period of high investment. Between 1995/96 and 2004/05 capital


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expenditure was $100m p/a. In the next 5 years from 2008, the company expects to spend around $500m p/a peaking at $780m on 2010/11.


The figures below come from the Ministry of Economic Development publication from late 2005 and cover the year ending 31 March 2003. Most of the figures are believed to be relatively stable.

Table 41: Electricity Distribution Statistics

Distribution Business Statistics

System Length km ICPs number

Electricity Supplied GWh

System Assets at ODV $000

Density ICPs/km

Average Consumption per ICPkWh

Alpine Energy 3,701 28,248 587 65,958 7.6 20,764 Aurora Energy 4,876 72,794 1,219 154,399 14.9 16,750 Buller Electricity 597 4,187 38 13,593 7.0 9,045 Centralines 1,549 7,442 109 24,953 4.8 14,654 Counties Power 3,307 31,214 409 92,553 9.4 13,114 Eastland Network 3,758 25,264 275 69,200 6.7 10,893 Electra 2,132 39,015 369 78,511 18.3 9,463 Electricity Ashburton 2,671 14,789 375 90,604 5.5 25,358

Electricity Invercargill 693 16,961 257 37,759 24,5 15,155

Horizon Energy Distribution 2,393 23,304 579 61,962 9.7 24,866

MainPower New Zealand 4,053 25,997 396 89,626 6.4 15,250

Marlborough Lines35 7,493 35,915 564 143,700 4.8 17,519 Nelson Electricity 242 8,614 142 13,531 35.6 16,524 Network Tasman 3,161 32,205 701 73,720 10.2 21,770 Network Waitaki 1,928 11,400 184 37,835 5.9 16,103 Northpower 5,431 47,785 864 111,626 8.8 18,080 Orion New Zealand 11,862 170,490 2,914 453,382 14.4 17,091 Powerco 24,978 293,479 2,734 703,268 11.7 12,621 Scanpower 873 6,638 87 15,900 7.6 13,050 The Lines Company 4,831 25,045 277 77,123 5.2 11,046 The Power Company 7,567 31,944 602 152,433 4.2 18,848 Top Energy 4,872 27,590 303 76,065 5.7 10,978 Unison Networks 8,026 102,449 1,110 223,393 12.8 14,517 Vector36 24,681 633,755 7,463 1,609,940 25.7 15,971 Waipa Networks 1,768 20,510 303 46,178 11.6 14,768 WEL Networks 4,742 73,959 957 161,763 15.6 12,945 Westpower 1,981 12,077 202 54,799 6.1 16,698 Industry Total 144,165 1,823,070 24,021 4,733,773 12.6 13,176


The key information for gas transmission companies is taken from the annual information disclosure statements the companies’ are obliged to provide. It is interesting to note that despite the Maui Pipeline being a significantly smaller network by length, it transfers higher volumes of gas than the NGC network.

35 Due to ownership structures, the data for OtagoNet JV is consolidated with that of Marlborough Lines. 36 This includes the Vector network that has now become Wellington Electricity.


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Table 42 Gas Transmission Statistics 37

Company System Length (KM) Customers Volume Transferred

NGC Holdings Limited (Vector owned)

2218.6 14 109 PJ

Maui Pipeline 308.3 13 137 GJ

Information on the individual distribution companies is taken from their websites/disclosure statements. Limited information is available on Nova Gas as they have an exemption from the information disclosure requirements as they were not perceived to have a dominant position.

Table 43 Gas Distribution Statistics Company System Length Customers Volume

Consumption

Vector 6,708 >140,000 22 PJ p/a

Powerco 5,600 100,000 n/a

GasNet 362 10,581 1 GJ

Nova Gas n/a n/a n/a



Transpower is a state owned enterprise that owns and operates the National Grid.


The list of electricity distribution companies is derived from the electricity networks association website.

The majority of electricity distribution companies in New Zealand are owned by energy trusts. These trusts are not generally involved in day to day management, but have the right to appoint suitably qualified directors on the board.

37 NGC Holding figures are for year ending 30 June 2008. Maui Pipeline figures are for year ending December 2007.


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Table 44: Ownership of Electricity Distribution Companies No. Company Owner

1 Top Energy Top Energy Consumer Trust

2 Northpower Northpower Electric Power Trust

3 Vector (UnitedNetworks) – Now Wellington Electricity

Cheung Kong Infrastructure Limited (CKI)

4 Vector Auckland Energy Consumer Trust

5 Horizon Energy Dist Eastern Bay Energy Trust

6 Counties Power Counties Power Consumer Trust

7 WEL Networks WEL Energy Trust

8 Waipa Networks Waipa Networks Trust

9 The Lines Company Waitomo Energy Consumer Trust

10 Powerco Babcock & Brown Infrastructure

11 Eastland Network Eastland Energy Community Trust

12 Unison Network Hawke’s Bay Power Consumers’ Trust

13 Centralines CHB Consumer Trust

14 ScanPower ScanPower Consumer’s Trust

15 Electra Electra Trust

16 Nelson Electricity Tasman and Marlborough (50/50 JV)

17 Marlborough Lines Marlborough Electric Power Trust

18 Network Tasman Tasman Electric Power Trust

19 Buller Network Buller Electric Power Trust

20 Westpower West Coast Electric Power Trust

21 MainPower MainPower Trust

22 Orion Group Christchurch City Council (87.6%)

23 Electricity Ashburton Ashburton City Council and local Co-operative

24 Alpine Energy Timaru District Holdings, LineTrust South Canterbury, Waimate & Mackenzie District Council

25 Aurora Energy Dunedin City Council

26 PowerNet Invercargill City Holdings, Southland Electric Power, Supply Consumer Trust

27 OtagoNet JV Marlborough Lines, Electricity Invercargill & The Power Company

28 Network Waitaki Waitaki Power Trust


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Gas Transmission

The main transmission line in New Zealand is owned by Vector, following the acquisition of NGC Holdings Limited. Vector is listed on the New Zealand Stock Exchange. Its major shareholder is the Auckland Energy Consumer Trust, which owns 75.1% of the company.

The Maui Pipeline is owned by Maui Development Limited, which itself is owned by the Maui Mining Companies (Shell Petroleum Mining Company, OMV New Zealand Limited and Todd Petroleum Mining Limited).

Gas Distribution

The ownership of the Gas Distribution businesses is as follows:

Table 45: Ownership of Gas Distribution Companies

Gas Network Owner

Vector Vector are stock exchange listed but 75.1% is owned by the Auckland Energy Consumer Trust

Powerco Babcock & Brown Infrastructure

GasNet Wanganui Gas which is 74.9% owned by Wanganui District Council

Nova Gas Nova Gas is substantially owned by the Todd Energy Group of companies.


4.2.1 Overview of the Process

Electricity Companies

As monopoly service providers, the network investments and charging arrangements proposed by Transpower and the electricity distribution business are subject to regulatory scrutiny. There are two authorities in New Zealand involved in the regulation of electricity networks businesses. These are:

1) The Commerce Commission (Commerce Commission); and

2) The Electricity Commission (Electricity Commission).

The Commerce Commission is responsible for the regulation of the distribution businesses, whereas this responsibility is split for electricity transmission between the Commerce Commission and the Electricity Commission. With respect to investments by Transpower, a significant distinction has developed between large-scale grid reinforcements/enhancements and all other items of capital expenditure. All large-scale grid reinforcements/enhancements are subject to the application of an


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economic test by the Electricity Commission, whereas the Commerce Commission sets thresholds for the remaining capital expenditure allowances and operating expenditures. (It should be noted, however, that the Electricity Governance Rules do not preclude the Electricity Commission from approving small-scale grid investments.)

In KEMA’s experience, it is an ongoing challenge for regulatory frameworks to address the interaction and trade-offs between capital and operating expenditures, even where they fall under a single jurisdiction. The separation of responsibilities for new investment capital and operating expenditures between two regulatory authorities represents a distinguishing feature of the New Zealand market. While these categories are arguably “splittable” it is nevertheless unusual for a regulated company to have to maintain separate regulatory interfaces with inevitable differences of regulatory approach and the potential for divergence.

Transpower and the distribution companies are subject to a targeted regime under Part 4A of the Commerce Act. The regime is defined as targeted, as businesses do not automatically become subject to control of their prices, revenues and or service quality. Under the Act, the network businesses only become potentially subject to controls if they breach one or more of the performance thresholds established by the Commission. These thresholds cover price and quality parameters.

The introduction of the Commerce Amendment Act in 2008 provided a requirement for a new input methodology for price controls and provided the potential for customized price-quality paths for selected distributors. This new legislation is covered in more detail in the later sections, but no investment decisions have yet been made under this legislation. This section therefore provides an overview of the latest round of assessments prior to this change, which will provide some guidance on the likely information requirements of the new process. It also provides an overview of what the new process will be and how it impacts on transmission and distribution businesses.

Gas Companies

The Commerce Commission is responsible for economic regulation of gas networks. There is no firm requirement for a price or quality control and therefore no planned timetable for review of each company’s investment plans. However, the Commerce Commission conducted an investigation in 2003-2004 on whether gas transmission and distribution goods and services supplied into the market should be subject to a control. In making this assessment the Commission was governed by Section 52-56 of the Commerce Act. This states that goods and services may be controlled if:

Competition is limited or is likely to be lessened in a relevant market; and Control is necessary or desirable in the interests of persons who acquire or supply the

goods or services in the affected market or markets.


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The Commission recommended that the gas pipeline services of Vector38 and Powerco met the Section 52 requirements for introduction of a control. The other gas companies were not seen as meeting the requirements and therefore no control was imposed.

Gas pipeline businesses will be subject to the Commerce Amendment Act 2008 and this will change the way these are regulated and the investment plans assessed. Details of the current process applied to Vector and Powerco and the future processes are outlined below.

4.2.2 Current Assessment Process


The assessment process for the transmission businesses’ investment plans is split between the investment process required by the Commerce Commission and that required by the Electricity Commission

Requirements of the Commerce Commission

The electricity transmission business is required to remain within published price and quality thresholds and controls may be imposed if threshold are breached. The price-path (CPI-X) threshold has now been redefined into three separate thresholds for Transpower:

1) Revenue requirement threshold applying until 30 June 2011;

2) A threshold limiting capital investment not currently requiring Part F approval by the Electricity Commission applied until 30 June 2008, and reset annually thereafter for the 2008/09, 2009/10 and 2010/11 financial years; and

3) System operator services threshold applying until 30 June 2011.

A fourth threshold will maintain the current quality threshold set out in the Commerce Act. The administrative settlement agreement provides a revenue restriction (by placing constraints on the input revenue building blocks) for Transpower, together with an absolute, one year cap on capital expenditure for investments in:

Asset replacement; Asset refurbishment; Asset enhancement and development (non-Part F); and Operational network information and technology services (IT).

The revenue threshold allows for revenues to increase for investments that are approved under Part F by the Electricity Commission (and for Business Support investment), provided that Transpower can demonstrate it has conformed to the principles and formulae underlying the threshold settlement. 38 This only relates to the Vector controlled Auckland gas distribution business and not the transmission and distribution assets that were later purchased from NGC. These ex-NGC assets are not part of the current Authorisation despite now being owned by Vector.


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These principles form the building blocks that are recognizable under many regulatory regimes covering operating costs, capital expenditure, valuation of the asset base, allowed rate of return, and tax and depreciation.

Requirements of the Electricity Commission

The role of the Electricity Commission in the regulatory regime for Transpower’s capital expenditure is evolving. The Electricity Commission undertakes a number of activities that impact both directly and indirectly on Transpower’s capital expenditure on specific grid investments and consequently on the revenue that Transpower needs to recover.

The Electricity Commission is required under Part F of the electricity governance rules to:

Determine Grid Reliability Standards; Determine a Grid Investment Test for assessing investment, including values for:

– discount rates – value of unserved energy

Determine the “Core Grid”; Prepare a Statement of Opportunities on at least a biennial basis including developing

grid planning assumptions (including supply and demand forecasting and scenario development);

Establish and maintain a central data set for the grid network; Approve Transpower’s pricing methodology; and Approve Transpower’s Grid Upgrade Plans (GUP).

While the Grid Investment Test (GIT) can in principle be applied to all capital expenditure relevant to the regulated services that Transpower provides, in effect the use is currently limited to major grid expansion projects. Expenditure for asset Replacement and Refurbishment (R&R), smaller projects and programs for asset enhancement and development and IT spend are currently excluded from the GIT in practice, but there is no legal limitation in the Electricity Governance Rules that prevents the application of the GIT to smaller scale grid investments.

Types of Capital Expenditure

There are four broad categories of capital expenditure identified which are subject to different scrutiny and approval processes. These include:

1) Grid investment that is Part F approved;

2) Currently excluded by the Electricity Commission from needing Part F approval;

– asset replacement; – asset refurbishment; – asset enhancement and development (non-Part F); – operational network information and technology services (IT);


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3) New investment contracts (customer led); and

4) Business support investment.

High-level descriptions of the regulatory oversight and approval mechanisms associated with the above types of capital expenditure are provided in the following sections.

Grid Investment Subject to Electricity Commission Approval under Part F

Major capital investments in the transmission grid (greater than NZ$1.5M), that are not customer specific investments (undertaken pursuant to bilateral new investment agreements), are currently subject to ex-ante approval following the application of an economic test by either the Electricity Commission or Transpower (depending on whether the investment is a “reliability” investment or an “economic” investment) under Part F of the Electricity Governance Rules. There are two categories of investment considered under the Part F rules, each having a different approvals process:

1) Reliability investments: Reliability investments have to meet two hurdles, first that they are required to meet the Grid Reliability Standards and secondly, that the investment option minimizes the market cost under the Grid Investment Test; and

2) Economic investments: Economic investments have to meet the single economic test prescribed under the GIT, and must have positive net market benefit.

Grid investments subject to Electricity Commission approval under Part F are considered on an ongoing basis and are not subject to a specific review timetable or a defined review period. Timetables are set by the Electricity Commission on an ad hoc basis.

Grid Investment not Subject to Electricity Commission Approval under Part F

Regulatory oversight for investments in asset Replacement and Refurbishments (“R&R”), small network enhancements (<NZ$1.5M) and IT related expenditure, is provided via the Commerce Commission’s application of a non-Part F threshold. An annual threshold (or cap) for allowed expenditure is determined by the Commerce Commission following a review of business plan forecasts and the underlying planning processes including asset management. This review was undertaken by consultants with the report published by the Commerce Commission as supporting information.

Once caps have been established, investigations would be triggered by the Commerce Commission should any of these expenditure thresholds be exceeded within the year to which the threshold applies. Such an investigation would be recognizable as a regulatory review of that expenditure. The administrative settlement provides for the non-Part F threshold to be set annually by way of an expert third Party Review on the behalf of the Commerce Commission for the duration of the settlement. Otherwise there is no ex-ante or ex-post review of expenditure unless a threshold has been breached.

The expert third party business plan review is an annual process. The non-Part F threshold is set by the Commission for a single year following a three to four month review of Transpower’s expenditure


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forecast for the year ahead and the processes and policies that underpin the decision making/approval of the forecasts.

Typically, this review process commences in December and continues until April during the time that Transpower is finalizing their business plans/budgets for the year commencing 1 July. The Commerce Commission or the consultant may suggest some adjustments to its expenditure forecast and will then set this amount as a cap on expenditure for the year ahead. At the end of the year (by 30 September following the year ending 30 June), Transpower is required to submit a threshold compliance statement (independently audited) which confirms compliance or otherwise with the four thresholds (revenue, non-Part F, system operator services and quality).

In the case of non-Part F revenue, there are a few limited circumstances which may permit Transpower to spend more than the cap and not officially breach the threshold. This includes Force Majeure or where Security of Supply is compromised and the Security of Supply “event” will result in expenditure in excess of $5m and Transpower can demonstrate that it cannot reasonably accommodate this amount within the threshold. Alternatively, Transpower could exceed the expenditure threshold and then determine unilaterally not to include the over spend in its regulated asset base – until the end of the settlement period in 2011 (i.e., spend at the shareholder’s expense).

Failing these mechanisms if Transpower spends more, then it breaches the threshold. The Commerce Commission can (at its discretion) seek to:

a) Enforce the deed of settlement agreed between it and Transpower (i.e., require Transpower to comply with the deed through the courts); or

b) Initiate a post breach inquiry under Part 4A of the Commerce Act, which could lead to either:

No action; A declaration of an intention to declare control of Transpower’s prices; or An administrative settlement to resolve the breach.

There is no other ex-post review of non-Part F capital expenditure built into the process other than when a consultant reviews the next year’s capital expenditure and considers the outcome of previously planned versus actual expenditure relevant to the current threshold.

Under the amendments to the Commerce Act, the Part 4A provisions/post breach inquiry procedure will no longer apply and will be replaced by pecuniary penalties and summary offences described later.

New Investment Contracts (customer led)

The Electricity Commission has no role in the approval of customer led investments. However, Transpower’s ability to enter into customer led contracts is subject to two conditions:


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1) The investment contracts are consistent with the required content of the grid reliability standards (i.e., there is a reliability standard within the contract that is compatible with the achievement of the grid reliability standards for the remainder of the power system); and

2) Transpower notifies the Electricity Commission of the proposed investment contract.

The regulatory oversight of this type of investment is limited to dispute resolution provisions regarding the establishment of such agreements. The investment costs of these contracts are borne entirely by the specific customer and hence, are not subject to the administrative settlement proposal with the Commerce Commission.

New investment agreements are excluded from being specified services, for the purposes of the Part 4A thresholds, if:

For contracts entered into after 5 June 2003, the other party agrees in writing that the terms and conditions are reasonable or reflect workable or effective competition for the provision of the goods or services; or

Transpower demonstrates beyond reasonable doubt that the new investment was approved under a process (regulatory or otherwise) that provides for affected customers to make and approve price-quality tradeoffs and opportunity for competitive provision of new investment by parties other than Transpower.

Business Support Investment (including minor fixed assets)

This investment is outside the direct jurisdiction of both regulators, but is regarded as minor by the Commerce Commission. The revenue thresholds in the administrative settlement do not define (or quantify) a business support revenue cap that may be breached – rather the settlement imposes a set of process constraints or, in some cases, fixed inputs (i.e., operating expenditure) that apply to the way that Transpower determines its overall revenue requirement. The return on capital associated with business support capital expenditure is not subject to any constraint or scrutiny as such, but, when setting the non-Part F Capex, the Commerce Commission (supported by an expert consultant) will check that expenditures have been appropriately allocated across categories (i.e., business support, non-Part F, customer, Part F, allocation to system operator, etc.).

Funding Capital Expenditure

The funding of capital expenditure for developments in the grid under Part F is unlimited, provided that such expenditure is approved by the Electricity Commission.

The administrative settlement provides for capital investments approved by the Electricity Commission (the lesser of what is spent and what is approved) under Part F to be fed through the revenue requirement formula to increase the allowed revenue that will be recovered by the transmission pricing methodology.


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The recovery of a return on capital expenditure outside of the class that is approved by the Electricity Commission under Part F (excluding expenditure undertaken pursuant to new investment contracts) is limited to the threshold amounts determined pursuant to terms of the administrative settlement.


The current price-quality thresholds relating to electricity distribution businesses were set in April 2004 and were due to expire in April 2009. The process of resetting these thresholds was begun in 2007 and a number of documents were published. However, with the introduction of the new legislation, this process has been suspended. Instead, for the one year period from 1 April 2009 to 31 March 2010, he existing thresholds will remain. It is worth considering the process that was being pursued prior to this suspension to understand the general level of information the Commerce Commission would require.

The Commission applied two thresholds for the period commencing in April 2004. This consists of a price-path threshold of a CPI-X form and a quality threshold. The establishment of two thresholds recognizes that there is a trade-off between the price and quality of distribution services.

The distribution business would breach the price path threshold if its average price changed by more that CPI-X amount. In establishing the CPI-X path the Commission used a comparative approach with the X factor being the sum of:

A “B” factor reflecting industry-wide improvements in efficiency determined through Total Factor Productivity; and

A “C” factor reflecting the relative performance of groups of distribution businesses with productivity C1 and profitability component C2. The productivity factor involved determining relative distribution business productivity using multilateral total factor productivity (MTFP) analysis based on the information disclosure data. The profitability component looked at average profitability from 2000-2003 based on post tax “residual” rates of return.

In setting these thresholds the Commission has drawn on information from a number of sources, but particularly cites two consultant reports prepared by the Commission39. These reports were based on the information disclosure data that the distribution businesses are obliged to provide on a regular basis. Companies had the opportunity to make submissions on the draft decision and the initial report prior to the final decision.

In making its determination the Commission allocated line businesses to four groups, which were assigned a different price. All businesses have incentives to make efficiency improvements to avoid breaching the thresholds. Businesses with below-average productivity, or with relatively high prices, faced a steeper price path than more productive business, or those that have consistently low prices.

39 Regulation of Electricity Lines Businesses, Resetting the Price Path Threshold (Initial report) and Comparative Options and Regulation of Electricity Lines Businesses, Analysis of Lines Business Performance (1996-2003) (Final Report) both by Meyrick and Associates.


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There were three distribution businesses that had been consistently maintaining lower prices while exhibiting higher productivity.

These businesses were allowed to gradually increase prices to more efficient and sustainable levels without breaching the price path threshold. This is shown in the table below.

Table 46: X Factors for Network Businesses

In addition to the price-path threshold, the distribution business had to comply with quality thresholds. These were:

Reliability criteria, requiring no material deterioration in reliability, measured in terms of SAIDI and SAIFI, with the current year’s reliability performance compared against average SAIDI and SAIFI from 1999 to 2003; and

Consumer engagement (or customer communication) criteria, requiring meaningful engagement with consumers to determine their demand for service quality, assessed through qualitative review.

Each distribution business needs to annually provide a threshold compliance statement. This requires a self-assessment with sufficient supporting evidence of whether the business has complied with the threshold. Where the Commission has identified a breach it can investigate the recent, current and


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future performance of an identified business. The “post-breach inquiry” was designed to investigate whether the performance of the business is consistent with the aims of the regime (i.e., the business is limited in its ability to earn excessive profits, faces incentives to improve efficiency and to provide services at a quality that reflects consumers demand and share the benefits of efficiency gains with consumers). An overview of the steps available to the Commission following any breach is shown in the diagram below.

Figure 41: Actions taken after a Threshold Breach

There are a considerable number of breaches as is shown in the table below. However, despite this large number of breaches, the Commission has never imposed control in response to a threshold breach. There have been a number of administrative settlements being agreed with the network companies and there are some post-breach inquiries that are still continuing.


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Table 47: Number of Threshold Breaches

Alpine Energy - - - - Y √ Y √ - - Y √ - - Y - 6 5 1Aurora Energy - - - - - - - - Y √ Y √ - - Y - 4 3 1Buller - - - - - - - - - - - - - - - - 2 2 0Centralines - - - - Y - - - Y - - Y - - - 4 0 4Counties Power - - - - - - - - - - Y √ - - Y - 2 1 1Eastland Network - - - - - - - - Y √ - - Y - - - 2 1 1Electra - - - - Y - - - - - Y Y - Y - 7 0 7Electricity Ashburton - - - - - - Y - - - Y √ - - Y - 3 1 2Electricity Invercargill - - - - - - - - - - Y √ - - Y - 5 4 1Horizon Energy - - Y √ - - Y √ Y - - - - - - 3 2 1MainPower - - - - - - - - - - Y √ - - - - 2 2 0Marlborough Lines Y - Y - Y - Y - Y Y - Y Y - 10 0 10Nelson Electricity - - - - Y √ - - Y √ - - - - - - 3 3 0Network Tasman - - - - Y √ - - Y √ - - - - Y - 3 2 1Network Waitaki - - Y - - - Y - Y √ Y - - - Y - 7 2 5Northpower - - - - Y √ - - - - - - - - Y - 2 1 1Orion New Zealand Y √ - - - - - - Y √ Y √ - - - - 4 4 0Otago Net - - - - Y - Y - Y Y - Y Y - 9 0 9Powerco - - Y √ - - Y √ Y - - - - - Y - 6 4 2Scanpower Y √ - - Y √ Y √ - - - - - - Y - 5 4 1The Lines Company - - - - - - - - - - - - - - - - 1 1 0The Power Company - - - - Y - - - Y - - Y - Y - 6 0 6Top Energy - - - - Y √ Y √ Y √ - - - - Y - 6 5 1Unison Y √ Y √ Y √ Y √ Y √ - - - - - - 8 8 0Vector - - - - - - Y - Y √ Y - - - Y - 6 3 3Waipa - - - - - - - - Y √ - - - - - - 3 3 0WEL - - - - - - - - - - - - - - - - 1 1 0Westpower - - Y √ - - Y √ Y Y √ - - - - 5 4 1

Total 4 3 6 4 12 7 12 7 17 10 13 8 6 0 16 0 125 66 59

Reset Thresholds2008

Price Quality2005

Price Quality2007

Price2006

Decision Not to

Declare

Decision Not to

Declare

Decision Not to

Declare

Decision Not to

Declare

Decision Not to

Declare BreachBreach

Decision Not to

Declare

Price Quality

Breach Breach Breach Breach RemainingTotal Breaches Cleared

Quality

BreachDecision

Not to Declare

BreachDecision

Not to Declare

Reset Process

The 2009 reset process (before suspension) provided an illustration of the process being followed for setting the new price-quality threshold. This includes four main stages as set out in the process paper that was published in July 2007:

1) Discussion stage – overall structure and type of thresholds including consultative packages. This includes an examination of investment incentives, price/quality trade offs and other pricing related issues;

2) Methodology stage – comprehensive consultation paper on the form of threshold and range of threshold levels;

3) Decision stage – 2-step consultation process and conference; and

4) Technical drafting – consult on the Gazette notice used in setting thresholds.

An overview of the intended timeframe for the reset process is shown in the diagram below.

Figure 42: Planned Timetable for the Reset Process


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The discussion paper was published in December 2007. This outlined a desire to continue with CPI-X regulation with retention of the B factor reflecting the aggregate productivity of the industry relative to the economy. Two options were being considered for addressing relative productivity and profitability across the companies. This was either retention of the existing C factors or one-off price adjustment. The later methodology paper indicated a desire to continue with a relative productivity factor, but that profitability should be dealt with by an adjustment to prices at the start of the period (P0). This should only address the relative profitability levels and not efficiency differences between the distribution businesses.

In determining the appropriate value for the price path elements the Commerce Commission had a choice between a building block approach and benchmarking. Implementing full building blocks is seen as an information intensive exercise, as it focuses on the firm’s own costs and estimates of efficient costs. The Commission considered that the relatively small size of the distribution businesses in New Zealand, and the resources required to undertake these reviews, would make this excessive. The Commission’s view was that a partial building block approach (derived only from actual historic costs and not forecasts of efficient costs) and benchmarking were most consistent with the regulatory framework.

The Commission recognized that the derivation of consistent information would be required for any P0 adjustment and that this would include data on revenue, operating costs, asset value and depreciation. The Commission was planning further research in this area before including the result in the initial decision paper, although the process was suspended before this date.

To inform the Commission’s analysis they had commissioned six consultant papers that were released alongside the discussion paper. This included an assessment of “Distribution Networks and Asset Management” by Farrier Swier Consulting. This used information provided as part of the normal Information Disclosure process in addition to a S98 notice issued to the Distribution business requiring information on their investment plans and asset management strategies.

This report had identified that a number of the distribution businesses could require moderate renewal increases in the 2009-2014 period and more significant increases in the 2014 regulatory period. One option being promoted by the Commission was the introduction of an additional incentive factor to the price-path threshold. This would allow increased notional revenue for distribution businesses having significant renewal investment plans. This was not considered necessary for the 2009-2014 period, but more likely to be required in the following regulatory period. Where individual distribution businesses did have additional investment requirements during the 2009-2014 period it was considered that these should be addressed through customized thresholds. These were planned for development during 2009 and implementation during 2010.

The Commission planned to set a quality threshold to ensure distribution businesses hit performance targets. However, at the time of the methodology paper it recognized that further research was needed to determine how historic performance and peer-group based data may best be used to incentivize the service quality improvements.


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The process was suspended before the initial decision paper could be produced. However, much of this analysis is likely to inform decisions made with the new processes being established.

Gas

The Minister of Energy announced the decision to impose controls over Vector and Powerco in 2005. The Provisional Authorization introduced average price reductions (P0) for Powerco and Vector and constant prices. This was an interim measure while the final authorization was consulted on.

In making the final authorization the Commission has adopted a building blocks methodology to determine the allowable revenue (Building Blocks Allowable Revenue). This is calculated as:

Regulated Rate of Return * Regulatory Asset Base

+ Depreciation - Revaluation Gains

+ Operating Expenditure - Capital Contributions

+ Tax

= Building Blocks Allowable Revenue

There has been a relatively long process for determining this calculation. Key elements included determining the Regulatory Asset Base for both companies and the level of capital expenditure. A detailed review of Powerco’s and Vector’s proposed capital expenditure was undertaken by PBA as the Commission advisor. Due to the information asymmetry between the Commission and the businesses the Commission has not sought to decide what investments the business should make for controlled services, instead it has carried out an assessment of the proposed capital expenditure forecasts so that to the extent practical only efficient investment are provided for on an ex-ante basis. This includes an assessment of the demand forecasts of the two companies.

In PBA’s preliminary expenditure review they undertook a top-down approach using international benchmarks (Australian distributors) of distribution spending and a bottom-up approach assessing the components of the proposal for their efficiency and reasonableness. The recommendations of the Commission were predominately based on the bottom-up approach given that this is the first control period and that capital expenditure requirements can vary from year to year. This review did also consider a high-level assessment of the asset management plans of both businesses.

In their initial review as part of the draft decision (October 2007), PBA recommended an 18% average reduction in the proposal submitted by Vector and a 68% average reduction in the proposal submitted by Powerco. This was partly due to Powerco proposing a capital expenditure that was over 60% higher than the average from the previous years with insufficient information to justify this expenditure. However, the draft decision noted that they had been hampered by poor information and that this could be substantially revised.


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Vector did provide some information to fill the gaps and made some relatively minor adjustments. Powerco provided a different set of proposals with different supporting information including a large increase in their planned investment for the 2008-2012 period. PBA concluded that the additional information provided by Powerco made it impossible for them to make recommendations on a bottom-up approach. PBA therefore adopted an Alternative Review Method for considering the proposals. This entailed a review of historical expenditure levels including the 2007 actual and 2008 budgeted expenditure to gain a sound baseline of expenditure for 2002-2012.

The end result of this re-examination was an increase in the recommended capital expenditure for Vector to around 10% below what they proposed. The PBA recommended reduction for Powerco was 32% including a suggestion (not accepted by the Commission) that some of this expenditure should be ring-fenced and recovered on an ex-post basis. The Commission was concerned that this outcome could be perceived as rewarding poor information, but noted that, in the latter part of the Authorization process, Powerco has attempted to provide the Commission and its advisors with better information.

The building block approach (including analysis of expenditure) has resulted in an allowed revenue for 2008-2012 for each of the distribution businesses. This is translated into a regulated price path using a CPI-X weighed average price cap. For the purposes of implementing the initial price changes required as part of this Authorization there was also a need for a P0 reduction that took effect from 1 January 2009.

4.2.3 Current Assessment Process

This is the assessment process that will be needed as part of the Commerce Amendment Act 2008. Under this legislation the Commerce Commission has a choice of different forms of regulation that it can apply. This includes:

Information disclosure regulation; Negotiation/arbitration regime – parties negotiate on matters such as investments,

service quality and price; Default/customized price-quality regime; and Individual price-quality regulation.

These types of regulation can be applied by themselves or in combination (except that both forms of price-quality information can not be applied).


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Input Methodologies

There will be a requirement for the Commission to publish binding input methodologies for the price-quality regimes and the potential for customized prices-quality regimes for firms facing particular circumstances (e.g., extensive capital investment). This was seen as a definite process improvement by some stakeholders.40

An overview of the anticipated input methodologies is shown in the diagram below. This breaks down the “methodologies” into high-evel approaches (regulatory guidelines) and specifications. These divide up into:

Regulatory guidelines – include methodologies by regulatory instrument and by sector covering cost of capital, asset valuation, depreciation etc.; and

Implementation specifications: – regulatory processes and rules; – how the Commission intends to apply the input methodologies to each sector; and – sector specific ‘requirement and ‘evaluation criteria’ relating to customized price-

quality path proposals from regulated business. (Only applying initially to gas pipeline and electricity distribution services).

40 Commerce Commission Seeks Views on Applying New Price Control Law – Ben Gully Jan 2009


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Figure 43: Role of Input Methodologies in Amended Commerce Act

The Commission has outlined the timetable for the process it intends to follow in developing these input methodologies and this is shown in the table below.


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Table 48: Process for Developing Input Methodologies

Process Indicative timeframe

1. Regulatory Provisions of the Commerce Act: Discussion paper published for consultation. This paper will provide an overview of the amended Act and its implications, including detail on the process for determining input methodologies.

December 2008

2.

Guidelines Discussion Paper published for consultation. This paper will discuss matters associated with evaluating or determining the cost of capital, valuation of assets, allocation of common costs, the treatment of taxation, and pricing methodologies, as set out in section 52T(1)(a) and (b) of the Act.

Q2 2009

3. Cross submissions invited in response to the submissions received on the Discussion Paper. Directly after the submissions received

4. Conference on the Guidelines Discussion Paper. Q3 2009

5. Draft input methodologies for each type of regulated service published for consultation. Q4 2009/ Q1 2010

6. Determination of input methodologies for each type of regulated service, in a Commerce Commission ordnance with section 52W of the Act.

By 30 June 2010

Source: Commerce Commission

There are a number of provisions in the Act relating specifically to the type of business being regulated. This also covers transitional issues related to the move to the new arrangements and these are described below.

Penalty Provision

One important change with the Commerce Amendment Act covers the penalty provisions for breaches of regulatory provision and appeals. The Act allows for various types of order upon breach of the provision including:

Requiring compliance; Imposing a pecuniary penalty for breach – this can be for contravening information

disclosure or price-quality regulations and could be up to $500k for an individual or $5m for a company;

Requiring payment of compensation for a breach – this can occur where a pecuniary penalty is imposed; and

Convicting a person for a breach and requiring them to pay a fine – the Act makes it a criminal offence to knowingly/intentionally contravene an information disclosure or price-quality requirements with a fine of up to $200k for an individual and $1m for a company.

There is also a right of appeal to the high court on the merits of determinations on input methodologies and on customized and individual price-quality paths.


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Transpower is subject to both information disclosure and price-quality regulation. The type of price-quality regulation that applies to Transpower needs to be determined following the expiry of its administrative settlement that lasts until 30 June 2011. This will be based on a recommendation to the Commission by the Minister. The CAA does not specify what form of price control applies to Transpower, but instead sets out a formula for determining this following the expiry of the administrative settlement. Before this expires the Minister must declare what price-quality regulation should apply:

Default/customized price-quality regulation; or Individual price-quality instrument.


All electricity distribution businesses will be subject to information disclosure regulation. In addition, those distribution businesses that are not customer owned will also be subject to default/customized price-quality regulation. A distribution business is classified as consumer owned if it meets the following criteria:

All the control rights and all the equity return rights (within the meaning of Section 3 of the Electricity Industry Reform Act 1998) in the supplier are held by one or more customer trusts, community trusts, or customer co-operatives;

The trustees of each customer trust or community trust, or the directors of each customer co-operative, as the case may be, that is referred to in paragraph (a) are elected solely by the persons who are consumers of the supplier, and at least 90% of the persons who are consumers of the supplier at the time of the election are eligible to vote in those elections;

At least 90% of the persons who are consumers of the supplier as at an income distribution resolution date benefit from that income distribution; and

The supplier has fewer than 150 000 ICPs.

The Minister needs to provide an initial list of the distribution businesses that are customer owned and hence, exempt from the default/customized price-quality regulation. This list is expected to be published in advance of 1 April 2009. However, this list is for information purposes only and there is the potential for change in status after that date.

The Commission does not intend to determine new information disclosure requirements until applicable input methodologies have been developed. All information requirements determined prior to the new Act continue to apply to distribution businesses. The Commission may continue to research new information disclosure requirements, which may be particularly important for consumer owned distribution businesses that are subject only to information disclosure regulation and not price-quality regulation.


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The thresholds for distribution businesses will be replaced by default/customized price-quality regulation with the first reset due to be implemented by 1 April 2010. During the interim period the existing price and quality thresholds will apply for a further year for the non-consumer owned distribution businesses. During this period any breaches of these thresholds will be treated under the old requirements and will not be subject to the new Penalty provisions in the Commerce Amendment Act.

The Commission needs to reset the default price-quality paths even if the relevant input methodologies have not been determined. As part of this process of resetting starting prices, rates of changes and quality standards, the Commission must consult with interested parties. If the input methodology is published after 1 April 2010 and would have resulted in a materially different price-quality path being set, then the Commission may reset the default price-quality path in accordance and could apply claw-back for the difference. Any default price-quality path will not apply until at least 4 months after a summery of the determination is published in the Gazette. The first determination therefore needs to be published by 1 December 2009. Further information on what needs to be produced as part of a default price-quality path determination (applying to distributors and gas pipelines) is provided later in this section.

Starting prices for the distributors need to be either the prices that applied at the end of the regulatory period or prices based on the current or expected future profitability of the distributor. A single rate of exchange (X%) needs to be applied for all goods and services and must be based on the long run average productivity improvement rate. Quality standards may be prescribed in any way the Commission considers appropriate and may include responsiveness to customers, reliability of supply, reduction in energy losses and voltage stability.

If a distributor does not believe the default price-quality path is appropriate it can make an application for a customized price-quality proposal. The application process and the implications of this application are provided below.

Gas Pipelines

Gas pipeline services are subject to information disclosure and default/customized price-quality regulation. There are a number of pipelines that are listed in Schedule 6 of the Act as exempt41 from both forms of regulation. This includes Nova Gas Limited, which has its own networks that compete with some of the gas distributors. This leaves the following gas companies that are subject to regulation.

41 Todd Taranki Limited, Swift Energy New Zealand Limited, Methanex New Zealand Limited, Energy Infrastructure Limited and Petroleum Infrastructure Limited, Vector Limited (Kapuri – Fault Road Mixing Station) and Nova Gas Limited.


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Table 49: Gas Pipelines Subject to Regulation Transmission Distribution

Vector Limited Powerco Limited

Maui Development Limited Vector Limited

Wanganui Gas Limited

Vector and Powerco are already subject to the Commerce (Control of Natural Gas Services) Order 2005. The default/customized price-quality regulations will not apply to these businesses until the control expires on 1 July 2012.

The Commission needs to make a determination setting out the information disclosure requirements for gas pipeline businesses as soon as practical after 14 October 2008. However, this needs to specify the input methodologies that apply, which cannot yet be done. Until this new information disclosure requirement is made, the existing information disclosure requirement made under the Gas Act 1992, continues to apply.

The default/customized price-quality regulation is due to commence on or after 1 July 2010. Any determination needs to be published in the Gazette four months prior to commencement, which requires a completion date of 1 March 2010. A similar process, explored above, for electricity distribution businesses will apply with the need to consult, set starting price, rates of change and quality standards. If gas pipeline businesses are not satisfied with the default price-quality path they can apply for a customized price-quality path.


The agreement of regulatory expenditure through the price-quality path relies heavily on the information disclosure that all the network business will be required to undertake. Additional information can be requested and provided as illustrated in the Authorization undertaken for Vector and Powerco and the S98 request used to obtain additional information from the distributors as part of the abandoned reset process. However, it does appear that a lot of the required information is extracted straight from the information disclosures and that is expected to continue in the future with the stated aim for default price-quality paths to be set in a relatively low cost way using readily available information.

This section provides an overview of these regulatory information requirements and the type of information that is provided on an annual basis.


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Electricity Transmission and Distribution

The Commission does not intend to determine new information disclosure requirements until applicable input methodologies have been developed. All information requirements determined prior to the new Act continue to apply to distribution and transmission businesses until new requirements are made. This consists of:

Electricity Information Disclosure Requirements 2004 (consolidating all amendments to 31 October 2008);

Electricity Information Disclosure Handbook; and Handbook for Optimal Deprival Valuation of System Fixed Assets.

In addition, for electricity distribution companies, there is an additional document with which they need to comply:

Electricity Distribution (Information Disclosure) Requirements 2008.

An overview of each of these documents is given below.

Electricity Information Disclosure Requirements 2004: This document primarily relates to Transpower covering the financial period from 2003/04 and all subsequent years. It does apply to distributors for the financial years from 2003/04 to 200/07, but not for later years when the Electricity Distribution Information Requirements have come into effect. The requirements include some that apply to Transpower only and some that specifically exclude Transpower.

Key areas that relate to Transpower are:

Financial statement disclosures; Transactions with related parties; Contracts that need disclosing; Financial and efficiency performance measures; Derivation of financial performance measures; Annual DHC reconciliation report; Energy efficiency performance measures and statistics; Reliability performance measures; and Pricing methodologies.

This information needs to be provided within 5 months of the end of the financial year. There are a number of schedules and forms in the document which provide more detail on the specific information that needs to be compiled. The financial information needs to be audited and information also certified by Directors of the company.

Electricity Distribution (Information Disclosure) Requirements 2008: These regulations apply in respect to the financial year ending on 31 March 2008 and for distribution businesses, replace the Electricity Information Disclosure Requirements.


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Key requirement are disclosures relating to:

Financial statements; Asset valuations; Prescribed contracts; Financial and efficiency performance measures; and Asset management plans.

The information generally has to be provided within 5 months of the end of the financial year (some are before the start of the financial year), but there are some transitional provisions. There is a specific requirement that all disclosures need to comply with the Electricity Information Disclosure Handbook. There are also schedules that indicate the forms that need to be completed and certificates that need to be signed by Directors of the business.

Electricity Information Disclosure Handbook

This handbook applies to both Transpower and the distribution companies, although certain sections relate only to distributors. The purpose of this handbook is to provide Transpower and the distribution businesses with:

A mandatory business accounting separation and allocation methodology; Details of transfer payments and other related party transactions, which must be

disclosed; and Details of the asset management plans that must be disclosed (Distributors only).

Handbook for Optimal Deprival Valuation of System Fixed Assets

This describes the methodology for valuing the system fixed assets of Transpower and the distribution businesses. In addition, certain schedules of the Distribution Disclosure Requirements are based on the replacement costs of system fixed assets, which needs to be determined using the methodology in this handbook.

Gas

The Gas (Information Disclosure) Regulations 1997 will continue to apply to gas pipeline companies until the Commission makes a determination on the new information requirements.

Key requirements for disclosure (as at September 2007) include:

Financial statements; Prescribed agreements; Wholesaling activities; Financial and efficiency performance measures; Energy efficiency performance measures and statistics; Reliability performance measures;


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Pricing methodologies; Methodologies for allocation of costs, revenues; Pipeline capacity disclosures; and Line charges.

There is a requirement for the financial information to be certified by an auditor and other key information to have a certificate signed by Directors of the company.

It is unclear what additional information will be requested from gas pipeline companies for the calculation default price-quality path. The evidence from the Vector/Powerco Authorization was that the consultants did request significant information on the capital expenditure and asset management strategy of the two companies. It is unclear whether a similar level of information would be required for a default price-quality path.


At the highest level the Commerce Amendment Act that impacts on gas and electricity makes two specific asset management requirements.

The first requirement is, as part of the information disclosure requirements, there is a list of the information that may be required. This specifically includes asset management plans.

The second requirement relates to the content and timing of price-quality paths. It states that a price-quality path may include incentives for an individual supplier to maintain or improve its quality of supply and those incentives may include:

“ reporting requirements, including special reporting requirements in asset management plans, if the suppler fails to meet the quality standards”.

Additional asset management requirements for the individual industries are highlighted below. However, there are no prescribed asset management processes or standards that the network companies are expected to follow.


The Electricity Governance Rules and Regulation (Part F) covers the requirements for Grid Upgrade plans, which include major grid reliability and grid economic investments. Part F Rule 12.3.1 states that a Grid Upgrade Plan must include a comprehensive plan for asset management and operation of the grid.

Transpower, in their asset management plan, also notes that the Commerce Commission uses the asset management plan as a reference for proposed expenditure. However, there is no specific requirement for this in the information disclosure requirements.


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The Electricity Distribution (Information Disclosure) Requirements indicate the requirements to publicly disclose an asset management plan before the start of each financial year. The Electricity Information Disclosure Handbook lays out the process that needs to be followed in the production of this plan. It is expected that electricity businesses will implement best practice asset management processes. The handbook describes the core elements of best practice for asset management plans as:

Focus on performance measurement, monitoring and continuous improvement; Are closely aligned with corporate vision and strategy; Are driven by business objectives and service level targets; Clearly assign responsibilities and accountabilities for asset management; Emphasize knowledge of what assets are owned and why, the location of the assets

and the condition of the assets; Emphasize optimizing asset utilization and performance; Encourage the use of “non-network’ solutions and demand management techniques

as alternatives to asset acquisition; and Take a total life cycle approach.

The handbook also provides a description of the mandatory content of the asset management plans of:

Summary – brief overview and key information; Background and objectives – including purpose of the plan, interaction with other

objectives, periods covered by the plan (which must be at least 10 years), date of approval by the Board of Directors, descriptions of stakeholders interests, descriptions of accountabilities in the distribution business and details of the asset management systems and process including asset management systems/software and information flows;

Assets covered – description of distribution area, network configuration, network assets by category, justification for the assets;

Proposed service levels need to include – customer orientated performance targets, other targets relating to asset performance, asset efficiency and effectiveness and efficiency of the distribution business. In addition, justification for these service levels should be included;

Network development planning – planning criteria and assumptions, prioritization methods, demand forecasts, distributed generation and non-network solutions policies, analysis of network development options and selected program;

Lifecycle asset management planning – description of maintenance planning criteria and assumptions, routine and preventative inspection and maintenance policies, asset renewal and refurbishment policies, asset replacement and renewal expenditure;

Risk management – methods, details and conclusions of risk analysis and details of emergency response and contingency plans;


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Evaluation of performance – progress against plan (physical and financial), comparison of actual performance against targeted objectives and a gap analysis and identification of improved initiatives; and

Expenditure forecasts and reconciliation – forecasts of capital and operating expenditure for minimum 10 year period and reconciliations for the most recent year that is available. The asset management forecasts for the first 5 years need to be disclosed with other financial statements and audited.

The asset management plan needs to be approved by the Board of Directors and present forecasts in current $NZ terms. All significant assumptions need to be clearly identified in the plan, which also need to be published and publicly disclosed.

Within 5 months after the end of the financial year, each distribution business must complete Report AM1: Expenditure Forecasts and Reconciliation. This needs information from the most recent and previous asset management plans.

Gas

The gas information disclosure requirements were assessed in 2000 and a number of key changes were announced. These announced changes included a requirement for pipeline owners to disclose specified asset management planning information for their gas networks. This was designed to promote good asset management practices by pipeline owners.

The announcement noted that the disclosure requirements were to be developed to be compatible with industry asset management standards and a draft Gas Information Disclosure Handbook was to be circulated. However, the latest version of the Gas (Information Disclosure) Regulations 1997, which was updated as at September 2007, contains no mention of asset management and there is no reference to the Gas Information Disclosure Handbook. Powerco, in their 2008 submission, noted that in the absence of a Gas Information Disclosure Handbook, they had relied on the Electricity Information Disclosure Handbook.

The overview section of the Commerce Commission website does state that the Commission needs to make a determination on information disclosure regulations applicable to each gas pipeline business “as soon as practicable” after 14 October 2008. This states that the determination may require suppliers to disclose certain specified information relevant to their performance (such as financial statements, prices and quality performance measures), including forward-looking information (such as forecasts and asset management plans).



The economic regulation of the network industries is primarily undertaken by the Commerce Commission with additional regulation of Transpower by the Electricity Commission.


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Commerce Commission

The Commerce Commission is New Zealand’s primary competition regulatory agency. It is an independent Crown entity and is not subject to direction from the government in carrying out its enforcement and regulatory control activities.

The purpose of the Commission is to promote dynamic and responsive markets so that New Zealanders benefits from competitive prices, better quality and greater choice. Underlying the Commission’s purpose are three strategic goals which are:

1) Markets are dynamic and goods and services are provided at competitive prices;

2) Consumers are confident of the accuracy of information they receive when making choices; and

3) Regulated industries are constrained from earning excess profits, face incentives to invest appropriately and share efficiency gains with consumers.

The Commission enforces legislation that promotes competition in the New Zealand market and prohibits misleading and deceptive conduct. It has responsibility for enforcing a number of pieces of legislation, which includes the electricity and gas industries and these are described below.

In order to ensure compliance, the Commission undertakes investigations and, where appropriate, takes court action. It considers applications for authorization in relation to anti-competitive behavior and mergers and assesses compliance with performance thresholds of electricity businesses.

Electricity Commission

The Electricity Commission is a Crown Entity set up in 2003 to oversee New Zealand’s electricity industry and markets.

The principal objectives, as set out in the amended Electricity Act, is to ensure that electricity is produced and delivered to all classes of consumers in an efficient, fair and reliable and environmentally sustainable manner. The Commission is also required to promote and facilitate the efficient use of electricity.

The Electricity Commission needs to operate in a manner consistent with New Zealand’s Government Policy Statement. This outlines the government’s expectations for the effective operation of the electricity market and identifies three priority areas:

1) Security of supply and reserve generation;

2) Priority investment in the transmission grid; and

3) Hedge market arrangements and demand-side participation.


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The role in transmission reflects a concern that there has been little significant investment in the grid in the last two decades and this could create problems at peak times. The Electricity Commission has been given a role to address these issues by approving a grid-pricing methodology for Transpower to upgrade the grid in critical places and resolving contractual difficulties between Transpower and the companies which receive services from the national grid.

4.5.2 Relevant Legislation

In New Zealand, the legislative framework for electricity transmission is determined by two Acts (as amended), the Commerce Act 1986 and the Electricity Act 1992. High-level descriptions of the relevant aspects of these acts are provided in the following sections.

Commerce Act

The Commerce Act promotes competition and provides tools to protect consumers from potential abuses of market power. The Act provides for the establishment of the Commerce Commission with powers to exercise control over markets for goods and services where there is limited or diminished competition in the supply of those items. Part 4A of the Commerce Act contains provisions specific to electricity that provide for the economic regulation of network businesses. The purpose statement in Part 4A of the Commerce Act 1986 (Section 57E) states:

The purpose of this subpart is to promote the efficient operation of markets directly related to electricity distribution and transmission services through targeted control for the long-term benefit of consumers by ensuring that suppliers:

Are limited in their ability to extract excessive profits; Face strong incentives to improve efficiency and provide services at a quality that

reflects consumer demands; and Share the benefits of efficiency gains with consumers, including through lower prices.

With respect to electricity transmission, the Commerce Act provides the framework for controlling the revenue recovered from transmission customers and has explicit provisions that would enable the transfer of those powers from the Commerce Commission to the Electricity Commission at some later date. Constraints on Transpower are created by the determination of thresholds that set limits for the required price-path and quality standards.

Commerce Amendment Act 2008

The Commerce Amendment Act came into force on 14 October 2008 and amends the regulatory provisions in Parts 4, 4A, 5 and 6 of the Commerce Act. The amendments directly affect the scope and role of the Commerce Commission in regulating electricity and gas networks. Key features of the new regulatory framework relevant to this assessment are:

A new purpose statement – this is a new Part 4 and supersedes the purpose in the Commerce Act. It allows regulation to be imposed where there is little competition


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and there is scope for the exercise of substantial market power. The purpose of the Act is: – provides for regulation of the price and quality of goods and services in markets

where there is little or no competition and little or no likelihood of a substantial increase in competition.

A broader range of regulatory instruments. This allows one or more of: – information disclosure; – negotiation/arbitration regime; – default/customized price-quality regulation; and – individual price-quality Instruments.

Use of upfront regulatory ‘input methodologies’ for the price-quality regimes; Provisions relating to the regulations of electricity lines and gas pipelines; and New appeal and penalty rules for breaches of regulatory provisions.

Electricity Act

The Electricity Act sets out additional arrangements for the regulation of New Zealand’s electricity industry. For the purpose of this report the sections of direct interest are Parts 14 and 15.

Part 14 contains provisions for making regulations. Specifically, electricity governance regulations that outline specific areas that apply directly and only to Transpower. The Minister of Energy may make electricity governance regulations for purposes including:

Setting standards and making provision for common quality and security on the national grid (in part or the whole), and requiring industry participants to comply with those standards;

Setting the terms and conditions for connections to the national grid; Regulating the way in which expansions, replacements, or upgrades of the national

grid or parts of the national grid must be evaluated, undertaken and funded, including specifying: – the circumstances in which Transpower must generally carry out expansions,

replacements, or upgrades; – particular expansions, replacements, or upgrades that Transpower must carry out;

and – the methodology by which the costs for expansions, replacements, or upgrades

must be allocated among industry participants or the actual allocation of those costs, and providing for their payment by industry participants.

Obligations for Transpower to report in relation to forecasts of medium-term system adequacy;

Requiring the use by Transpower of a specified methodology or component of a methodology for allocating Transpower’s revenue requirement to individual users; and

Providing for financial instruments for managing risks relating to transmission losses and constraints.


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The regulations include provisions for the monitoring and enforcement of the governance rules. The rules are amendable by the Minister, which provides a more flexible regulatory framework.

The governance rules are made by recommendation by the Electricity Commission, which has specific objectives and functions to which it must adhere, including giving effect to the relevant Government Policy Statement.

Gas Act 1992

This replaced the 1982 Act and introduced a series of measures including:

Removal of exclusive franchise provisions and obligations of incumbents to supply gas;

Removal of retail and wholesale price controls; Identification of a gas operator and gas suppliers; Issuing and citation of codes and standards; and Introduction of Information Disclosure.

Two sets of Regulations were put in place pursuant to this Act. These were:

1) Gas Regulation 1993 – Mainly safety and technical issues so not considered further;

2) Gas Information Disclosure Regulations – This was introduced with three objectives:

a) stimulate competition by allowing identification of profitable opportunities;

b) ensure that parties negotiating with gas companies have key information; and

c) assist policy makers and consumers to determine whether companies are setting monopoly prices.

The Gas Information Disclosure Requirements have been amended since 1997 with the latest edition containing revisions until September 2007. It will be superseded when the Commerce Commission publishes new requirements as part of the Commerce Amendment Act. Details on the information required as part of this report is detailed in the earlier section.


The Commerce Amendment Act states that default/customized price-quality regulation will be applied to electricity distribution businesses (except those exempt due to consumer ownership) and gas pipeline services that are subject to regulation. This form of regulation may also apply to Transpower, although the option exists of also applying individual price-quality regulation.

Under default/customized price-quality regulation the Commission will set default prices that apply for a regulatory period and require all distributors/pipeline operator to follow these prices. This will include starting prices, rates of changes, quality standards and dates for commencement. These


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regulated companies do have the option of making a proposal to the Commission for a customized price-quality path, which once set will apply for a set period instead of the default price-quality path. Dates for making these alternative proposals will be contained in the default price-quality path.

An outline of the information that needs to be included in the default price-quality path determination is specified in Section 53M of the Act as follows:

(1) Every price-quality path (whether a default price-quality path or a customized price-quality path under this subpart, or an individual price-quality path under subpart 7) must specify:

(a) in relation to prices, either or both of the following with respect to a specified regulatory period:

(i) the maximum price or prices that may be charged by a regulated supplier:

(ii) the maximum revenues that may be recovered by a regulated supplier; and

(b) the quality standards that must be met by the regulated supplier; and

(c) the regulatory period.

(2) A price-quality path may include incentives for an individual supplier to maintain or improve its quality of supply, and those incentives may include (without limitation) any of the following:

(a) penalties by way of a reduction in the supplier's maximum prices or revenues based on whether, or by what amount, the supplier fails to meet the required quality standards:

(b) rewards by way of an increase in the supplier's maximum prices or revenue based on whether, or by what amount, the supplier meets or exceeds the required quality standards:

(c) consumer compensation schemes that set minimum standards of performance and require the supplier to pay prescribed amounts of compensation to consumers if it fails to meet those standards:

(d) reporting requirements, including special reporting requirements in asset management plans, if the supplier fails to meet the quality standards.

(3) Quality standards may be prescribed in any way the Commission considers appropriate (such as targets, bands, or formulae) and may include (without limitation):

(a) responsiveness to consumers; and

(b) in relation to electricity lines services, reliability of supply, reduction in energy losses, and voltage stability or other technical requirements.

(4) A regulatory period must be 5 years.

(5) However, the Commission may set a shorter period than 5 years if it considers that it would better meet the purposes of this Part, but in any event may not set a term less than 4 years.

The default price-quality path will automatically apply to those companies that are subject to price-quality regulation unless they have applied for a customized price-quality path.


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Customized Price-Quality Path

At any time after the default price-quality path is set by the Commission the pipeline or network business can make an application for a customized price-quality path. The exact timing is subject to an annual “cut off” date and a supplier can only make one proposal during the regulatory period and can not apply 12 months before a default price-quality path is set. It is not possible to withdraw a proposal once it has been submitted to the Commission.

The Commission may determine any customized price-quality path it considers appropriate and the company will be bound by this path. The customized price-quality path will normally apply for 5 years, but can apply for a minimum of 3 years. The rules states that when setting the customized price-quality path the Commission can:

Set a price-quality path that is lower, or otherwise less favorable to the regulated supplier, than the default price-quality path that would otherwise apply;

If it sets a lower or a higher price than applied under the default price-quality path, apply claw-back; and

With the agreement of the supplier, vary an input methodology that would otherwise apply to the supplier.

The claw-back in Clause b could require a temporary lowering of prices or allow a supplier to recover some or all of any shortfall in revenues achieved from the previous prices. This can be spread over a period of time to minimize consumer price shocks or financial hardship to the network company. Once a customized price-quality path expires the company automatically moves to the default price-quality path unless they have received approval for a new customized price-quality path. This may result in starting prices moving when transferring between the different paths.


This section outlines the process that the Commission and the utilities need to follow for the setting and re-setting of a price-quality path.

Setting the Default Price-Quality Path

Default price-quality paths will apply to regulated companies for a regulatory period and are set by the Commission in a “relatively low cost way” using readily available information. The Commission is obliged to consult with interested parties when setting or re-setting the default price-quality path.

One restriction faced by the Commission in setting the default price-quality path is that they may not use comparative benchmarking on efficiency to set starting prices, rates of changes, quality standards or incentives to improve quality of supply.

Starting prices need to be either prices that applied at the end of the preceding regulatory period or prices determined by the Commission that are based on the current and projected profitability of the company. The Commission will normally set a single rate of change for each type of business. This


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“X” should be based on the long-run average productivity improvement achieved by either New Zealand supplier or comparable companies. The Commission can also take into account the effects of inflation on supplier inputs when setting the X factor.

Quality standards can be prescribed in any way that the Commission considers appropriate.

Any default price-quality path determination needs to be published in the gazette at least 4 months before the determination comes into effect.

Customized Price-Quality Path

The Commission has 40 working days to assess any customized price-quality proposals and determine compliance with input methodologies. If there are deficiencies with the proposal the Commission can request the submitting company to rectify these within 40 days or the process may be discontinued. The Commission should make a determination within 150 days of receiving a complete proposal subject to any extensions granted or prioritization of proposals.

The Commission is not required to consider any more than four proposals relating to the same type of good or service in each year. Excess proposals can be deferred to a subsequent period. In prioritizing proposals the Commission can consider:

Quality and completeness of the initial proposal; Urgency of any proposed additional investment (compared to historic rates of

investment) required to meet consumer requirements on quality; and Materiality of the proposal relative to the size and revenues of the supplier.

In the Discussion Paper on the Commerce Act the Commission has indicated that their initial view is that they will prioritize proposals as soon as initial proposals are received.

Compliance Obligations

The Commerce Amendment Act 2008 requires the setting of an annual date by which compliance must be demonstrated. The Commission may require by written notice one or more of the following from a regulated company:

A written statement that states whether or not the supplier has complied with the price-quality path;

A report on the written compliance statement that is signed by the auditor; Sufficient information to enable the Commission to properly determine whether all

applicable price-quality paths have been complied with; and A certificate in the form specified by the Commission to and signed by at least one

director of the supplier, confirming the truth and accuracy of any information provided.


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No specific guidelines exist for the preparation of asset management plans.


There are clear guidelines for the preparation of asset management plans in the Electricity Information Disclosure Handbook. This contains 14 pages of detail on what information needs to be provided by the distributor and an explanation of why this information is required. However, within this specification there is no detail on any specific asset management standards that electricity distributors are expected to adopt.

These plans have been reviewed annually by Commerce Commission appointed consultants. As part of the publication of the 2007/08 review, the AMP published their purpose for these disclosures, which could be seen as providing guidance on what is expected.

An AMP is the principal internal company document that drives asset investment planning, which in turn informs factors such as profits, costs, asset values, price, quality, security and reliability of supply, about which the purpose statement of the Act requires the public to be informed.

Sound asset management planning is an integral part of ensuring that EDBs improve efficiency and provide services at a quality that reflects consumer demands. In a light-handed regulatory regime where there is no ex-ante approval of investments, there is a need for transparency and accountability to ensure businesses are making rational decisions about ongoing investment and that services to consumers are supplied at the appropriate level of quality.42

These asset management plans are regularly reviewed with PBA having been appointed for these reviews. The 2006/07 report found considerable variability in the quality of the plans submitted with inadequate forecasts for future capital and maintenance expenditure being a particular area of concern for some of the distributors. Some recommendations were made on how to improve the reporting requirements, but no specific best practice methodologies or approaches were recommended for adoption. The 2007/08 report focused only on the material differences between the 2006/07 and 2007/08 plans and found a similar level of compliance.

One change is that these plans now need to be produced at the start of the financial year, rather than 5 months after as is the case for most of the information. This reflects the fact that the Asset Management Plan should be a key management report needed to run the business and should feed into the business plan, which would be prepared before the start of the financial year.

42 Review of Electricity Line Businesses’ 2007/08 Asset Management Plans – Commerce Commission


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In addition to the guidelines for distribution businesses to complete the asset management plan, there is also a template that needs to be completed for the asset management information. This is shown in the table below.

Figure 44: Assessment Management Form for Distributors

Gas

There are no guidelines for gas businesses for preparation of an asset management plan.



The investment plan requirements will depend on whether the information is required by the Commerce Commission to calculate revenue requirements for asset replacement or refurbishment or for Grid Investment and Grid Upgrade Projects required by the Electricity Commission.

There are no specific guidelines for the preparation of investment plans for the Commerce Commission. The investment plans will normally be scrutinized by a set of technical consultants and will be expected to justify investment decisions. As part of the latest administrated settlement, Transpower is also required to annually determine its annual revenue requirements. However, this is constrained by the various building block components that were outlined in the settlement offer.


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The Electricity Commission investment plan requirements will vary in terms of the information needed for justification of a specific project or Grid Upgrade Project.


The Electricity Distribution Information Disclosure Requirements 2008 outlines three forms that need to be completed on capital expenditure. One of these is the asset management form provided above. The other two forms are:

1) Report FS2: Regulatory Asset and Financing Statement; and

2) Report MP2: Performance Measures.

Figure 45: FS2 Regulatory Asset and Financing Statement

REPORT FS2: REGULATORY ASSET AND FINANCING STATEMENT

ref Electricity Distribution Business:5 For Year Ended 06

7 Capital Expenditure on System Fixed Assets (by primary purpose) ($000)8 Customer Connection to AM1

9 System Growth to AM1

10 Reliability, Safety and Environment to AM1

11 Asset Replacement and Renewal to AM1

12 Asset Relocations to AM1

13 Total Capital Expenditure on System Fixed Assets - to AM1

14

15

16 Capital Expenditure on Non-System Fixed Assets - from AV1

17

18

19 Capital works roll-forward (for System Fixed Assets)20 Works Under Construction at Beginning of Year21 plus Total Capital Expenditure on System Fixed Assets - 22 less Assets Commissioned in Year - from AV1

23 Works under construction at year end - 24

25

26 Regulatory Investment Value calculation27 System Fixed Assets: regulatory value at end of Previous Year - from AV1

28 Non-System Fixed Assets: regulatory value at end of Previous Year - from AV1

29 Finance During Construction Allowance (on System Fixed assets) - 2.45%30 Total Regulatory Asset Base value at beginning of Current Financial Year - 31

32 plus (System Fixed Assets Commissioned in Year - from AV1

33 System Fixed Assets Acquired From (Sold to) a Non-EDB in Year - from AV1

34 Non-System Fixed Assets: Asset Additions - from AV1

35 Regulatory Asset Base investment in Current Financial Year - total - 36 Regulatory Asset Base investment in Current Financial Year - average - 37

38 plus (minus) where a merger or acquisition has taken place within the year39 Adjustment for merger, acquisition or sale to another EDB - from AV4

4041 Regulatory Investment Value - to MP2

0


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Figure 46: MP2 Performance Measures

REPORT MP2: PERFORMANCE MEASURES

ref Electricity Distribution Business:5 For Year Ended: 06 Performance comparators7

8 Current Yr - 3 Current Yr - 2 Current Yr - 1

9 Operational expenditure ratio10 - $m from FS1

11 - $m from AV3

12 Ratio (%) Not defined Not defined Not defined Not defined %

13

14 Capital expenditure ratio15 - $m from FS2

16 - $m from AV3


18

19 Capital expenditure growth ratio20 - $m from FS2

21 - MVA from MP1

22 $/kVA Not defined Not defined Not defined Not defined $/kVA

23

24 Renewal expenditure ratio25 - $m from FS1 & 2

26 - $m from AV1


28

29 Distribution Transformer Capacity Utilisation30 - MW from MP1

31 - kVA from MP1


33

34 Return on Investment35 - $m from FS1

36 - $m from FS3

37 - - - - $m

38 - $m from FS239 Ratio (%) Not defined Not defined Not defined Not defined %40 * If a Merger or Asset Transfer with another EDB was enetered into during 41 the year, the denominators are calcuated as time-weighted averages.

42 Expenditure comparison table43

44

45

Total circuit length (for

Supply)

Electricity Supplied to Customers' Connection

Points

Maximum coincident

system demand

Connection Point

46 ($/km) ($/MWh) ($/MW) ($/ICP)

47 Capital Expenditure ($) per Not defined Not defined Not defined Not defined from FS2 & MP1

48 Operational Expenditure ($) per Not defined Not defined Not defined Not defined from FS1 & MP149

($/MVA)

Not defined

Not defined

Previous Years: Current Financial

Year

Distribution Transformer

Capacity (EDB-Owned)

Expenditure metrics ($ per):

Capital & Operational Expenditure: Asset Replacement, Refurbishment and Renewal

Adjusted Regulatory Profit

Regulatory Profit / Loss (pre-financing and distributions)

Regulatory Investment Value

Regulatory Depreciation of System Fixed Assets

Maximum Distribution Transformer DemandTotal Distribution Transformer Capacity (at year end*)

less Interest Tax Shield Adjustment

0

Capital Expenditure: Customer Connection and System GrowthChange in Total Distribution Transformer Capacity

Total Operational ExpenditureReplacement Cost of System Fixed Assets (at year end*)

Total Capital Expenditure on System Fixed AssetsReplacement Cost of System Fixed Assets (at year end*)

Gas

There are no specific guidelines on the capital expenditure forms that gas businesses need to provide. Only two gas companies have so far been subject to controls and this may explain the lack of guidelines. The Authorization process that was implemented did note the difficulty of obtaining good information on capital expenditure from the gas pipelines.


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4.7 Summary and Lessons Learned

New Zealand is unusual in having a process of targeted price controls where companies are not automatically subject to controls, but become potentially subject to controls if they breach one or more performance thresholds. In addition, the use of benchmarking and partial building blocks to set thresholds is different to the full building block approach used in other jurisdictions. The system has led to many breaches of the price-quality thresholds, and while none of these have led to a control order, there have been administrative settlements needed for the larger companies.

The development of the new legislation recognizes the diverse set of distribution utilities in New Zealand in terms of size and ownership structure. The separation of the 1.8m customers into 29 distribution companies necessitates many small players. However, the unequal distribution of these customers gives rise to some players with significant market share and some participants with as few as around 4,000 customers to serve. The situation is made more complex by the ownership structure with many of the utilities owned by their customers and therefore not having the excess profit incentive that would be seen by shareholder owned company.

The new Commerce Amendment Act recognizes the small size and customer ownership incentives in the decision on what regulatory approaches to apply. Small consumer owned distribution businesses will only be subject to information disclosure, while the larger/ shareholder owned companies face default/customized price-quality paths in addition to information disclosure. The customized price-quality path will allow distribution businesses that are unhappy with the default path (possibly due to unusual circumstances for replacement investment) to apply for the customized path.

The current information disclosure requirements are quite extensive with the annual disclosures being the primary data used in setting previous price-quality thresholds and expected to be used for future default price-quality paths that should be based on readily available information. This disclosure also requires all distribution companies to produce asset management plans with clear guidelines as to the information that is expected to be included. This information disclosure is likely to become more important as it will be the sole method of regulation for the smaller companies.

Transpower is unusual in having two agencies that need to agree to different parts of their expenditure to maintain and upgrade the network. They are currently the subject of an administrative agreement and this will last until 2011 when either a customized price-quality path on individual price-quality regulation would need to be introduced. While they do not have explicit requirements from the Commerce Commission for their Asset Management plan, this will be a key element in agreeing revenue requirements and will be thoroughly reviewed by the Commission.

Most of the gas network companies have not been subject to regulatory controls with the exceptions being Vector and Powerco, who have a control that lasts until 2012. This was the result of a review in 2003/04, which cleared all other companies. However, the regulated gas companies will all shortly be subject to information disclosure and default/customized price-quality regulation as from 1 July 2012. There are some notable exceptions from either form of regulation including Nova Gas who provides competing pipelines to some of the major companies.


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While asset management plans are clearly needed for all businesses (either explicitly or as part of an investment plan review) there are no asset management standards or process that are enforced by the Commerce Commission or the Electricity Commission.

Future Focus

The future focus for the Commerce Commission is in implementing the changes in the Commerce Amendment Act 2008. There are a few significant projects that need to be undertaken in the next 2 years, which includes:

Establishing the input methodologies; Setting the default/customized price-quality plans for electricity distribution

companies (by 1 December 2009); Setting the default/customized price-quality plans for gas companies by 1 March

2010; Determining the new information disclosure requirements; and Determining whether Transpower should be governed by default/customized price-

quality regulation or an individual price-quality path regulation.

Appendix E: United States

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5. Appendix E: United States Background and Responsible Regulators

The US market is regulated by a mix of federal, state, and local entities depending upon jurisdictions and the utility services provided.

Electricity

The Federal Energy Regulatory Commission (FERC) regulates all electricity wholesale generation, wholesale power and wholesale transmission services that are not part of a unified vertical utility (with the exception of Texas, where the market does not cross the state boundaries). Vertically integrated utilities that provide generation, transmission and distribution services on behalf of their own customers are exempt from federal jurisdiction. FERC also regulates wholesale transactions of vertically integrated utilities that are not on behalf of a utility’s end-use customers. Since 2005, FERC has had its responsibilities expanded to include oversight over the reliability of the US electricity transmission grid, implementation of new tools to prevent market manipulation (including penalty authority), and the establishment of rules for incentive-based rate treatments for transmission in interstate commerce by public utilities (US Energy Policy Act of 2005). One of the key new goals of FERC is to change reliability standards from voluntary to mandatory. FERC is currently continuing in its efforts to reach this goal.

State Public Utility Commissions regulate vertically integrated utilities’ generation, transmission, and distribution in states where the electricity market structure has not changed from the traditional vertically-integrated monopoly utility model. In states where electricity market restructuring has unbundled transmission from distribution, the State Commissions retain jurisdiction over the utility distribution function. In addition, some states regulate certain aspects of municipal utilities and/or co-ops, including rates. The National Association of Regulatory Utility Commissioners (NARUC) represents State Public Service Commissioners at the national level and work in collaboration with the Federal Energy Regulatory Commission.

The exception to the rule is the Texas electricity market, which is considered by many to be the most advanced competitive state electricity market in the US. The Public Utilities Commission of Texas (PUCT) is the primary regulator for electricity wholesale markets and retail markets in Texas. This is due to the configuration of the Texas transmission grid, which is operated by the Electric Reliability Council of Texas (ERCOT) and covers 75% of Texas. The transmission grid ERCOT administers is located solely within Texas and is not synchronously interconnected to the rest of the United States. As a result, transmission of electricity occurring wholly within ERCOT is subject to the jurisdiction of the State Public Utilities Commission of Texas rather than FERC. The Texas PUC is also involved in the regulation of vertically integrated investor owned utilities outside of ERCOT where traditional bifurcation of state and federal jurisdiction remains in place.

Municipal utilities (Munis) are public power utilities that typically operate as natural monopolies for local electricity and/or natural gas distribution to end-users in their municipality. Munis are governed


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by elected public officials such as city councils or by boards of appointed or elected individuals and are non-profit organizations that typically operate as a division of the local city government and are not generally regulated by the state. 43 For example, City Public Service of San Antonio, the largest municipally-owned gas and electric utility in the US, treats its revenues as public funds and is subject to strict purchasing regulations and major decisions must be vetted by the community.44 Almost all Munis own their own distribution systems, while larger municipalities, such as CPS San Antonio, own their own generation, transmission, and distribution systems.

Electric Cooperatives are private, independent electric utilities, owned by the members they serve and run by a democratically elected board.45 Cooperatives are autonomous, self-help organizations controlled by their members. Membership is voluntary and open to all persons able to use their services and willing to accept the responsibilities of membership. In 1936, the federal government established the Rural Electrification Administration (REA) through which the federal government made direct loans and loan guarantees to electric utilities to serve customers in rural areas. Many cooperatives are distribution-only utilities. As a result, distribution cooperatives typically become members of power supply cooperatives, also known as “generation and transmission cooperatives”, which generate and/or procure electricity and transmit it to the distribution member systems.46 Most power supply cooperatives purchase their power from federal power marketing agencies (PMAs) which give preference in the sale of power at-cost to public bodies and electric cooperatives.47

The US Government established federal power marketing administrations (PMAs) to operate as federal agencies under the Department of Energy beginning in the early 1900s. The PMAs generate and transmit the power output from federal projects, which are mostly large hydroelectric dams. The PMAs are required by law to provide preferential treatment in generation and transmission services to public utilities like municipalities and cooperatives. FERC regulates the transmission of power from PMAs to utilities. The four PMAs include Bonneville Power Administration, Southeastern Power Administration, Southwestern Power Administration, and the Western Area Power Administration. In addition, the Tennessee Valley Authority (TVA) is generally regarded as a PMA as it operates in a similar function to these agencies. Each PMA is a distinct and self-contained entity within DOE, much like a wholly owned subsidiary of a corporation, while TVA operates as a federal corporation with private investors.48

Natural Gas

FERC regulates the interstate transmission of natural gas, natural gas pipelines, natural gas storage, and liquefied natural gas facility construction. FERC also has oversight of the construction and operation of pipeline facilities at US points of entry for the import or export of natural gas. Interstate

43 Milton B Lee. CEO, CPS San Antonio. Written Testimony to US House Committee on Energy and Commerce. March 15, 2007. 44 Milton B Lee. CEO, CPS San Antonio. Written Testimony to US House Committee on Energy and Commerce. March 15, 2007. 45 National Rural Electric Cooperative Association 46 US Department of Agriculture. Rural Utilities Service Website. 47 National Rural Electric Cooperative Association 48 US Department of Energy Website


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pipeline projects require FERC coordination with other federal agencies. The safety, standards, procedures, development and expansion of any pipeline system is the jurisdiction of the US Department of Transportation’s Office of Pipeline Safety. Mergers and acquisitions are viewed by agencies at the federal (including FERC, Department of Justice, Federal Trade Commission, etc.), state, and sometimes local levels.

State Public Utility Commissions have jurisdiction over intrastate natural gas pipelines and their associated local distribution systems including the local distribution company. Direct delivery to end-users via intrastate pipelines is also under State PUC jurisdiction. FERC has no oversight or jurisdiction over local natural gas distribution companies. In some states, cities have jurisdiction over distribution within city limits (this is the case for Texas). Local distribution companies (LDCs) differ in ownership structure with different levels of State Public Utility Commission oversight. LDC ownership types include:

Investor-Owned: State PUC has jurisdiction over all operational aspects, approves service rates, and reviews the quality of service;

Privately-Owned: Subject to State PUC regulations and rate-setting guidelines; Municipal: Local Municipal government retains authority over rates, operations, and

quality of service; and Cooperative: Run by members on non-profit basis.



In the 1990s, the US interconnected bulk power transmission systems began to be overhauled by the combined efforts of US legislative initiatives and Federal Energy Regulatory Commission Orders. The Energy Policy Act of 1992 (EPAct) mandated that the Federal Energy Regulatory Commission (FERC) open up the national electricity transmission system to wholesale suppliers on a case-by-case basis.49 Furthermore, the Act created the framework for a competitive wholesale electricity generation market and established a new category of electricity producer, the exempt wholesale generator, that were not subject to previous constraints on non-utility generation which made it easier for them to enter the wholesale electricity markets.50

In April 1996, FERC issued the landmark Order 888, which further opened access to US transmission networks. The objective of Order 888 was to “remove impediments to competition in wholesale trade and to bring more efficient, lower cost power to US electricity customers.51 The Order required public utilities to provide open access transmission service on a comparable basis to the transmission service they provide themselves and was designed to remedy undue discrimination or preference in access to

49 US Energy Information Administration Website 50 US Energy Information Administration Website 51 FERC website


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the monopoly owned transmission wires that control whether and to whom electricity can be transported in interstate commerce.52

EPAct 1992 and FERC Order 888 created the framework for competitive electricity markets in the US by establishing competitive generation rules and open access to transmission. In turn, these federal actions spurred state-led restructuring efforts. The US Energy Information Administration notes that “since the passage of Energy Policy Act in 1992 and issuance of FERC Order 888, states have been actively involved in industry restructuring by promoting competition in the retail markets for electricity”.

The first two states to pass electric power industry restructuring legislation were California and Rhode Island in 1996. Currently, twenty states, plus the District of Columbia, have implemented some form of restructuring efforts with wide variation in market activity due to variations in state policies. To date, Texas is the only US Market that is 100% competitive. In terms of market segments, the competitive retail electricity market remains heavily concentrated among non-residential or business segments, which combine for roughly 80% of all estimated competitive sales. The residential market is limited to a few active states; roughly 92% of total competitive residential sales are in Texas and New York.53

Post-1996, FERC has issued a number of complimentary and clarifying orders to Order 888 culminating in the December 1999 issuance of FERC Order 2000. Order 2000 was issued to encourage all transmission owners to voluntarily join regional transmission organizations operated by independent system operators with the purpose of addressing the engineering and economic inefficiencies inherent in the existing transmission system and to correct perceived or real discrimination by transmission owners.54


The deregulation of US Natural Gas Markets started in 1985 with FERC Order 436, which made it easier for local distribution companies and consumers to negotiate prices directly with producers and contract separately for transportation. However, Order 436 only led to partial restructuring as it encouraged rather than required pipeline companies to provide open access. Order 436 also failed to address “other key elements of pipeline company services,” notes the EIA, “for example, Order 436 did not provide similar incentives for pipeline companies to provide open access to storage facilities”. Although Order 436 was later vacated and remanded to FERC, the general intent of the order – to deregulate via the authority of FERC – and to institute transportation programs was upheld.

In 1992, FERC issued Order 636, known as the Restructuring Rule, which required interstate pipeline companies provide open-access transportation and to unbundle their sales from their transportation services. According to the EIA, “the rule was designed to allow more efficient use of the interstate natural gas transmission system by fundamentally changing the way pipeline companies conduct

52 FERC Docket No. RM05-25-000. Preventing Undue Discrimination and Preference in Transmission Services. 53 KEMA 2009 Restructuring Review 54 US Energy Information Administration Website . Status of Bulk Power Transmission Systems.


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business...the purpose of the unbundling provision was to ensure that the gas of other suppliers could receive the same quality of transportation services previously enjoyed by a pipeline company's own gas sales. Unbundling increased competition among gas sellers and diminished the market power of pipeline companies”.

Major Provisions of FERC Order 636:

1) Required pipeline companies to provide open-access transportation services that are equal in quality whether the gas is purchased directly from a pipeline company or elsewhere, such as from a producer or a marketer.

2) Encouraged the use and development of market centers where several pipeline systems interconnect and buyers and sellers can make or take gas deliveries. To facilitate the development of market centers, FERC encouraged pipeline companies to charge mileage-based rates rather than postage-stamp rates that have set charges for gas transported through a given area or zone regardless of distance.

3) Required pipeline companies to provide customers with unbundled services and expanded access to interstate storage capacity. Storage is integral to the efficient and reliable distribution of natural gas, and provides the means to supply consumers' needs at times when their requirements exceed total gas production and mainline transmission capability.

4) Established a capacity release market in transportation and storage capacity by allowing release of unwanted firm capacity and also allowing a replacement shipper to re-release capacity if permitted by the terms of the initial release. To help the capacity release market develop, FERC required pipeline companies to establish electronic bulletin boards to provide shippers with equal and timely access to information about the availability of service on their systems.

5) Required pipeline companies to redesign their transportation tariff rates so that the majority of fixed costs would be recovered through the capacity reservation fee charged to firm customers.

The restructuring of the natural gas industry – that began with Order 436 and was substantially completed by Order 636 – changed gas rates and transportation patterns as well as increased competition between local distribution companies and pipeline companies. The new structure of the market allowed large-volume customers to purchase natural gas directly from interstate open-access pipelines and bypass local distribution companies. In response, a number of states began requiring local distribution utilities to unbundle their sales and delivery services while also setting guidelines for delivery – “transportation services” – to large volume customers. Many states also introduced open-access transportation for large-volume customers. Overall, local distribution systems and local distribution companies remain the backbone of the US natural gas delivery system. There are no Federal Power Marketing Agencies for natural gas.


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In terms of natural gas residential choice programs, the majority of states have not instituted residential unbundling.

Residential Natural Gas Restructuring By State55 Status Number of States Statewide unbundling, 100 percent eligibility: Active

4 – DC, NJ, NY, PA

Statewide unbundling, 100 percent eligibility: Inactive/Limited Programs

4 – CA, MA, NM, WV

Statewide unbundling. Implementation phase: > 50 percent eligibility

6 – GA, IL, MD, MI, OH, VA

Pilot Programs/Partial Unbundling 8 – CO, FL, IN, KY, MT, NE, SD, WY No Unbundling 27 Pilot Program Discontinued 2 – DE, WI 5.1.1 Number of Companies

Electricity

US Electricity Transmission56

No of Transmission Companies

System Length (KMs)

Average System Length Per Company

Highest System Length

Lowest System Length

3,100 263,898 85 62,764 N/A

US Electricity Distribution

No. of Distribution Companies

Line Length (KMs)

Number of Customers

Average Line Length (KMs)

Average Number of Customers

3,100 N/A 137,298,683 N/A 44,290

55 EIA Natural Gas Residential Choice Programs. Released April 8, 2009. 56 T&D are not typically separated. An incumbent utility is both a transmission and a distribution utility. The EIA is in the process of separating transmission companies in its statistical surveys. As a result, the statistics for T&D are of “bundled” US utilities.


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US Electricity Transmission and Distribution Ownership57

Investor-Owned Municipal Cooperative Federal Total

293 1,845 936 5 3,100

Gas

US Gas Transmission58

No of Transmission Companies

System Length (KMs)

Average System Length per company



102 345,402 4,161 25,335 724

US Gas Local Distribution Companies

No of Distribution Companies

Line Length (KMs)

Number of Customers

Average Line Length (KMs)


1,307 140,563 70,427,641 108 53,885

US Gas Transmission Ownership

Intra-State Interstate Cooperative Federal Total

102 83 N/A N/A N/A

57 EIA Form 861 – 2007. Data does not explicitly show whether or not a specific utility owns the wires for their transmission and distribution. 58 The number listed for Gas Transmission companies is for intrastate transmission only. Source: EIA US Intrastate Gas Pipelines Workbook


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US Gas Local Distribution Ownership59

Investor-Owned Municipal Cooperative Privately-Owned Total

257 931 15 104 1307


US Electric Power System

Source: Platts, from mappery.com

59 EIA Form 176


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US Electricity Transmission Network

U.S. Natural Gas Pipeline Network, 2009


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The assessment of utility investment plans occurs within the overall process of setting rates.

5.2.1 Overview of the Process

The typical rate setting process is very legalistic, transparent and involves the following steps:

Pre-filing notice: To inform the Commission and/or the public that the utility is planning on requesting a rate increase. At this point, the utility would supply information as to how much of an increase is being requested, information regarding the type of test year to be used, the date the proposed increase would become effective and/or any other information required by the Commission. The pre-filing notice can serve to allow the Commission to establish its timetable for review and hearing of the case.

Filing of actual rate request: The bulk of the work in any rate case rests in preparing and putting together the actual rate case filing, in many cases using some form of a standard filing package.

Review of filing: Commission staff will review the filing and prepare its report to the Commission. In states where standard filing requirements are used, the initial task is to ensure that the utility has complied with those requirements. The primary purpose of the review, however, is to identify and review the major issues presented in the case and the utilities position on those issues. The staff must then concur with the utility’s position or develop and support its own position. In order to develop its position in the rate case, the staff will normally perform a field investigation, or in essence, an audit of the filing. Once the staff has completed its review, it will issue a report on its findings and recommendations to the Commission. This staff report is submitted to the Commission and to the utility, which can review the report, and in some cases, file objections to the staff’s findings and conclusions.

Actual hearing of the case: Or, in some complex cases, a pre-hearing conference may be held to: 1) group interveners with common causes so as to keep the number of participants involved to a minimum; 2) identify issues which can be agreed upon (or stipulated) by all parties (or at least the utility and the staff) and thus, limit the bulk of testimony and debate to the unresolved issues; and 3) set a timetable for hearings and develop the order of witnesses. The actual rate case hearing follows much the same pattern as a legal proceeding. Witnesses are called to give testimony, which is often prewritten in a question-and-answer format and filed in writing with the Commission prior to, or at the time of, the hearing. Each witness, upon completion of this “canned testimony,” can then be cross-examined by staff counsel and/or interveners. Normally, the utility’s witnesses will be called and cross-examined before the staff and interveners (if any) present their direct testimony and are cross-examined. The next phase of the hearing is presentation of rebuttal testimony and cross-examination by the utility. At this point, the utility may recall its witnesses to present testimony to rebut issues or points presented by the Commission staff or interveners during direct


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testimony. Following rebuttal and cross examination, the case then involves the filing of briefs which present, in writing, the positions and arguments for each group of participants. Reply briefs which address the arguments presented by other parties can then be filed by any party. The final phase in the case hearing is the presentation of oral arguments by the counsel for each party. These arguments act to summarize the party’s case

Rendering of decision: A hearing examiner usually hears the actual case and has responsibility for drafting the proposed Commission order. It is then the responsibility of the full Commission to review and record in the case and either approve or modify the hearing examiner’s decision. One it is approved, the Commission issues the order and serves it upon all parties involved in the case.

Appeals process: Any party which was involved in the rate case proceeding has the right to appeal the decision made by the Commission. In some states, the appeal is made to the Commission itself with further recourse to the state courts. In other states, the appeals process begins in the state court. In most states, the decision of the Regulatory Commission can be appealed as high as the state’s Supreme Court. No matter what direction the appeals process takes, the appeal can only be made on the basis of an error in the law. The findings of fact in the case must be accepted by the court as long as they are supported by the evidence of the record.

Electricity

FERC regulates wholesale sales of electric energy, capacity and ancillary services using a market-based rate authorization. Utilities seeking to participate must demonstrate that they or their affiliates do not have horizontal or vertical market power. Entities that have vertical or horizontal market power are required to use cost-of-service pricing. Transmission service companies and Independent System Operators (ISOs) are also regulated using a cost-of-service methodology. The regulatory process for setting rates is typically initiated by a filing from a regulated entity or by a filing from a market participant (complaint case).

Virtually all Public Utility Commissions use traditional cost-of-service ratemaking procedures for regulating the vertically integrated investor-owned utilities and/or IOU distribution utilities in their jurisdiction. It is important to point out, however, that no two state agencies regulate exactly alike and no two state electricity markets are precisely the same. The most notable difference is in Texas, where the Public Utility Commission has jurisdiction over wholesale and retail electricity markets plus traditional regulation of vertically integrated IOUs outside of ERCOT (the Texas Independent System Operator). As a result, the Public Utilities Commission of Texas uses market based solutions and benchmarking for its ratemaking procedures in competitive markets but continues to use traditional cost-of-service procedures in non-ERCOT parts of the state. In general, the ratemaking process for all states occurs via rate case, which is typically initiated when a state-regulated entity files for a rate change or if a market participant brings forward a complaint case.


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Municipalities and Electric Cooperatives are public power utilities and set their rates at levels sufficient to cover costs and retain a reserve for repairs and replacement of capital equipment. Some Munis, such as CPS San Antonio, contribute to their city’s general fund. Rates and revenues are set by the governing board of elected public officials or by boards appointed by elected individuals. Major capital investments require extensive civic (re: stakeholder) participation in the decision-making process.

Bonneville Power Administration uses cost-based rates to provide rates as low as possible to its customers that at the same time allow BPA to fully recover all of its costs including repayment of federal investment in its system. BPA sets separate rates for power (from its federal facilities) and transmission (from its federal transmission lines). BPA power facilities’ lines pay the same BPA transmission rates as any other market participant. BPA determines its revenue requirements through an internal review and then develops initial proposal rates that are usually defined in $/MWh. Technical studies, documentation, and testimony of BPA witnesses are used to support the case. The preliminary cost-based rate proposal is then evaluated and final rates are established in a formal, evidentiary rate case that is presented for review to customers and other parties. Written and oral hearings are then presented to the BPA Administrator for final decision. The Administrator’s “Record of Decision”, which includes the final proposed rates, is filed with FERC for confirmation and approval. Rate period have ranged from one to 5 years, although BPA seeks to establish rates for 2 year periods.

Gas

FERC sets natural gas interstate transmission rates by using a cost-of-service methodology. Rates are designed based on a pipeline’s cost of providing service including an opportunity for a transmission company to earn a reasonable rate of return.

According to the FERC Cost of Service Manual, there are five steps involved in cost-of-service ratemaking:

1) Establishing a revenue requirement, or cost-of-service;

2) Functionalizing the cost-of-service;

3) Cost classification;

4) Cost allocation; and

5) Rate design.

FERC also issues certificates of public convenience and necessity for interstate pipeline companies or wholesale entities seeking to expand their interstate transportation network. The key criteria for a new or expanded interstate pipeline is that the expansion promotes the public interest, is economically feasible, and will not have a major environmental impact.


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Most state Commissions, typically the Public Utility Commission (PUC), regulate local and intrastate distribution of natural gas using a cost-of-service methodology to determine rates. For example, in Texas natural gas distribution is regulated on a cost-of service basis by the Railroad Commission (separate from the Public Utilities Commission). Distribution utilities may apply or re-apply for a new rate case at any time. Financial and technical considerations are both weighed equally and there have been two recent distribution cases initiated to review potential overcharging. Overall, there is minimal engagement in economic detail but moderate to heavy engagement in technical and safety requirements for assets. As long as a company is operating safely and reliably, the RRC will not engage in the details of a company’s investment plan or asset management. There is no mandatory reporting. However, Texas is unique in that the RRC has jurisdiction over transmission utilities. Transmission companies negotiate their rates freely with their customers (as allowed by Texas law) and the only time there is regulatory review is when a customer files a complaint against a transmission company. The RRC may then set the rate on a cost-of-service basis (typical approach) or on a market-based basis (rare and no recent activity).

In terms of local governance, some cities have authority over the distribution of natural gas in their city limits (this is the case in Texas). In addition, municipalities set their own rates for customers. State Utility Commissions may serve as a final arbiter in a disagreement between local distribution companies and cities in rare instances.


Electricity The focus of FERC information requirements for market-based rate applications is on gathering information that shows the horizontal and vertical market power of the applicant. FERC requires two horizontal market power tests be completed by applicants and requires a description of vertical service offerings. The applicant must also define its “Seller Category”. In addition, FERC requires applicants provide information on all generation and transmission assets, and natural gas intrastate pipelines, and gas storage facilities by balancing area authority.

In terms of traditional cost-of-service ratemaking, both FERC and State Public Utility Commissions typically require information related to the following:

Authorized Rate of Return: Current investment marketplace and level of return necessary for investors;

Forecast Usage for Customer Class: Historical usage data broken down by customer class;

Revenue Requirement: Utility expenses; Revenue Allocation by Customer Class: Demand-based costs plus usage-based

costs methodology; sometimes marginal cost methodology is employed; and Electric Quarterly Reports: Public utilities and power marketers must submit

summaries of all contracts and transactions.


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Gas

FERC established a “Cost-of-Service Rates Manual” for interstate pipeline services in June 1999. The manual includes guidelines for interstate natural gas pipeline companies regarding the information required for each step of the cost-of-service ratemaking procedure.

The first step of the process, computing the cost of service formula, requires that utilities define the following components: return, operation and maintenance expenses, administrative and general expenses, depreciation expenses, non-income taxes, income taxes, and revenue credits. In addition, utilities must compute their rate base.

The second step, functionalizing cost-of-service, involves the direct allocation of operation and maintenance expenses and other costs to the functions of the particular company, typically storage and/or transmission. Pipelines are required to book their expenses to particular accounts under the FERC’s Uniform System of Accounts.

The third step, cost classification, is a two part process. Functionalized costs are identified as either fixed or variable whereupon the fixed and variable costs are then classified as reservation (demand) or usage (commodity). For fixed costs, utilities must list their investment costs, O&M expenses, A&G expenses, and third party reservation costs. Variable costs vary with volume throughput and primarily consist of purchased gas and fuel costs. Since FERC Order 636, most pipelines do not include fuel costs in their rates.

The fourth step, cost allocation, requires pipeline utilities to apportion costs by volume for jurisdictional and non-jurisdictional services. Zonal costs may also be apportioned using MDt-miles. Utilities must include load factor information as part of the cost allocation process.

The fifth and final step is the rate design. Information required includes: firm service rates, interruptible service rates, and interruptible rates computed as derivatives of firm rates.

At the state level, Public Utility Commissions require information related to the gas portion and non-gas portion of utility rates. In terms of purchased gas costs – the gas portion of rates – information requirements include the dollar-for-dollar purchases of the gas commodity, pipeline transportation and wholesale storage services. The non-gas portion – the rate base – includes costs related to the investment in the distribution system and the operational costs. In terms of new construction or expansion of distribution facilities, utilities must submit information that demonstrates the need for the project, adequate safety standards and project economics. The level and type of information required varies by state, however, state Commissions or agencies actively require this information.


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Electricity

No explicit asset management requirements from FERC or state PUC’s.

Gas

FERC Order 712, issued 19 June 2008, permits “market based pricing for short-term capacity releases and facilitates asset management arrangements (AMAs) by relaxing regulations to facilitate FERC’s prohibition on tying and on its bidding requirements for certain capacity releases”. Asset management arrangements occur when a “capacity holder releases some or all of its pipeline capacity to an asset manager who agrees to either purchase from, or supply the gas needs of, the capacity holder. A major component of asset management service is the purchase and sale of gas as a commodity. FERC has found that such service will provide benefits to the natural gas and electric markets”.



The legal authority of FERC began with its predecessor the Federal Power Commission (FPC). The FPC was established in 1920 by the Federal Water Power Act and served as the regulator for rates, financing, and services of companies operating dams. The Federal Power Act of 1935 and the Natural Gas Act of 1938 gave the FPC the legal power to regulate the sale and transportation of electricity and natural gas. Subsequent amendments and cases enabled the FPC to regulate natural gas facilities, established the FPC as the jurisdictional authority over facilities producing Natural Gas sold in interstate commerce and in intra-state sales of power transmitted across state-lines. In 1978, Congress reorganized the FPC into FERC and expanded the Commission’s responsibilities. The National Energy Policy Act of 1992 gave FERC “wheeling authority” to require utilities to allow third parties to move electricity across transmission lines. In January 2005, Congress passed a new Energy Policy Act (EPAct 2005) which granted FERC significant new responsibilities and significant legal new authority. The new responsibilities include:

Oversight of the reliability of the US electricity transmission grid, including the authority to oversee mandatory reliability standards governing the US electricity grid, the first time in its history that FERC has had the authority to oversee mandatory reliability standards governing the US electricity grid;

Implementing new tools to prevent market manipulation including Civil Penalty Authority which FERC has indicated it will use to clarify its market manipulation rules, assure regulatory compliance for regulated entities, and more easily identify violations;

Providing rate incentives to promote electric transmission investment;


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Supplementing state transmission siting efforts in national interest electric transmission corridors; and

Reviewing certain holding company mergers and acquisitions involving electric utility facilities, as well as certain public utility acquisitions of generating facilities.

The legal authority of state regulators was established by various state legislatures during the early 1900s as the size of the electric utility industry greatly increased. As utility service areas expanded beyond city boundaries and throughout particular states, the need for State Public Service Commissions became readily apparent. In 1907, the first state agencies to regulate the electric industry were established in Georgia, New York, and Wisconsin. Most US states quickly followed suit. Basic powers included the authority to franchise utilities, regulate rates, finance, service, and establish accounting systems.60 State legislatures, along with federal actions, continue to determine the roles and capabilities of state Public Service Commissions with each state choosing its own path. The history of state regulation in Texas case illustrates this point.

The Public Utilities Commission of Texas was not established until 1975 when it was given state-wide comprehensive regulatory jurisdiction of electric utilities. For approximately the first 20 years, the agency’s primary role was traditional economic regulation of the electric and telecommunications utilities. In 1995 and 1996, significant legislation occurred at the federal and state level that dramatically changed the Commission’s role by creating a competitive electric wholesale market. In 1999, the Texas legislature provided for the restructuring of the electric utility industry and the introduction of retail competition. While these legislative acts and further deregulation served to decrease the PUCT’s traditional regulatory functions, many of the traditional functions have been replaced by new challenges and responsibilities in overseeing the most active electricity market in the United States.

5.5.2 Codes, Rules, Fling Guidelines/Requirements

FERC publishes guidelines for filing requirements for electricity and natural gas utilities. Historically, FERC has relied on written testimony. The specific filings required vary significantly by utility type, industry, and areas of operation. Many of the guidelines for filing with FERC relate to electronic submission of forms and quarterly reports, however, certain documents may not be filed electronically. For electric and natural gas, these documents include any filing containing tariff sheets, annual transmission planning and evaluation reports, data responses and self reports pursuant to FERC investigation, material subject to protective order, discovery responses, dispute resolution service material, and documents with files larger than 50 MB.

FERC has established over 390 parts within its filing guide that direct utilities to the appropriate filing procedure. The guideline is continually updated in conjunction with the ever-changing role of FERC. For example, the Energy Policy Act of 2005 led FERC to adopt a new rule requiring potential developers of LNG terminals to initiate pre-filing procedures at least 6 months prior to a formal application. Guidelines exist for licensing, permitting, and exemptions of project costs, the filing of

60 EIA


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rate schedules and tariffs, applications for transmission service (electric), annual reports on interlocking positions (electric), shareholder reports, and further items related to the regulation of electricity and natural gas networks within the US.

State guidelines for filings vary from state to state with different levels of power over reports, management, affairs, licensing, certificates of public convenience and necessity, and audits of accounts. State Public Utility Commissions and Agencies annually update their filing guides for utility use.


Electricity

FERC sets rates using a number of different regulatory procedures. The three most common types of filing for electric market-based rate setting are:

1) Initial market-based rate applications;

2) Change in status reporting requirement filings; and

3) Updated market power analyses.

At the state level, the associated Public Utility Commissions and Agencies establish their own distinct guidelines and procedures depending on the nature of their jurisdiction and legal authority. For many states, the Administrative Procedure Act, which provided a uniform set of procedures for federal agencies, has served as a model for state administrative procedures.61

Gas

FERC sets rates in a number of proceedings:

1) A pipeline files for a rate increase. This is known as a “Section 4” rate case filing (Section 4 of the Natural Gas Act provides for this proceeding) and it is first brought before FERC’s litigation staff in the Office of Administrative Litigation. If there is a consensus on the issues in the application, then the case is resolved. However, if the issues cannot be resolved, a hearing is held before an Administrative Law Judge. In both instances, FERC will then act upon the results. A pipeline may file a “Section 4” rate case at anytime unless barred by a previous agreement. The pipeline must demonstrate that new rates are “just and reasonable”.

2) FERC files for a rate change due to evidence that “rates are no longer just and reasonable”. This is known as a “Section 5” rate case and is initiated by FERC or upon complaint from an interested party. FERC has the burden of demonstrating that

61 National Regulatory Research Institute. April 2003.


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current rates are no longer just and reasonable, and of establishing new rates that are just and reasonable.

3) Pipeline files for a “Certificate of Public Convenience and Necessity” to build a new pipeline, expand existing facilities, or offer additional services. This is known as a “Section 7” rate case and FERC will set the “initial rates” which remain in effect until the company files a “Section 4” filing in which all pipeline rates are reviewed.

4) Intrastate pipelines option. Intrastate pipelines may have their rates are set by FERC using cost-of-service methodology and a “fair and equitable” standard rather than “just and reasonable”. This is known as a “Section 311” filing. Intrastate pipelines may also elect to file with a state Agency instead.

5) Limited “Section 4” rate case filings by pipelines for new service or new rates or complaint proceedings that raise rate issues.

The procedures vary from state to state, although rate case hearings, mediation through alternative dispute resolution with participating stakeholders, and the issuance of certificates of public convenience and necessity have become standard among state regulators. Open-access policies and standards continue to promulgate at the local distribution level in many states with regulator involvement heavily depending upon ownership structure – IOUs and privately-owned utilities face more state regulatory scrutiny than Munis or Coops.



As discussed in the earlier sections, there are no explicit asset management requirements, and guidelines for the preparation of capital plans are covered in the procedures and information requirements for regulatory proceedings.

There is no explicit regulatory guidance regarding the preparation of justification for capital plans underlying a regulatory submission, but companies tend to follow a consistent approach based on experience and lessons-learned from past proceedings.


In the US, the focus of regulatory attention is to structure rates that are sufficient, but no more than sufficient, to allow utilities to cover their operating and capital costs, to attract needed capital and to maintain their financial integrity, and yet provide appropriate protection to the relevant public interests. The basic standard of rate regulation is the revenue-requirements standard, which provides revenues that allow a utility to cover operating costs and earn a reasonable rate of return on property devoted to the business. The determination of required revenue involves the determination of three major items: 1) allowable operating costs; 2) net value of the investment in property; and 3) a fair rate of return.


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Operating costs are calculated using “test year” information from a recent or projected 12 month period, adjusted as necessary. The net value of investment in property is referred to as the “rate base” and represents the capital of the company upon which a rate of return should be applied. This rate of return is determined by the regulatory agency and applied to the rate base to provide a fair return to investors.

To determine a rate of return on rate base that is appropriate for the overall cost of capital, the Commission first identifies the components of the utilities capital structure. The cost of each capital component is then determined and weighted according to its proportion of total capitalization. These weighted costs are summed to determine the overall cost of capital, which becomes the allowed rate of return on rate base. Capital programs must typically be documented in the filing package to be included in the capital structure. This documentation must include a description of the program, costs and benefits.

Many states utilize some form of standard filing package which must be used by a utility whenever it files for a rate increase. The use of a standard filing package allows the Commission staff to review the rate request based on the facts presented while not having to determine if all the facts are present. It is important that the utility present its request and issues based on complete information, because, as a legal proceeding, the case will be decided based on the facts on record (“findings of fact”).

Asset operating and maintenance (O&M) costs are reflected in test year information, not in the capital calculation. Standard filing requirements typically require that a utility file a recent Cost of Service Study (COSS) to determine costs to serve various classes of customers. This study captures operating costs for assets required to provide the service, and is used as an input to establishing different tariffs.

In determining the appropriate treatment of costs incurred by a company, the Commission must consider whether the company's actions, which results in such costs, are prudent. In deciding whether the actions of a utility are prudent, Commissions apply the "reasonable person” standard; that is, the standard of care a reasonable person would exercise under the same circumstances confronting the management of the utility at the time of the decision to take such actions.

The proper analysis for determining any type of economic sanction such as a disallowance of recovery for imprudent or unreasonable actions on the part of a regulated utility occurs in several steps. First, there must be a clearly understood definition of the standard of care by which a utility's performance can be measured; second, the actions of the utility must be examined to determine if there has been a failure on its part to conform to the standard required; and finally, there must be a reasonably close causal connection between the imprudent conduct, if any, and actual loss or damage. Actions by regulated public utilities which are found to constitute imprudent management that result in increased costs are generally disallowed.


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Since the US market is quite mature and established, key constructs of the rate making process are well engrained in utility strategies and approaches to regulatory proceedings. Due to the open nature of proceedings, outcomes can vary dramatically based upon the parties involved and the dynamics of the relationships between regulators and stakeholders. Given this environment, lessons-learned are not always consistent, and can change across geographies and over time.

Areas of Future Focus

Many US utilities will be facing aging asset situations that will require capital investment programs that are out-of-bounds with past experience. The regulatory scrutiny of these requests is anticipated to be significant, and the supporting analysis will require the adoption of many of the fundamental aspects of an asset management approach. Many companies are establishing asset management functions and tools in anticipation of this situation. Whether this will be a trend or a necessity for all utilities is yet to be seen.

Appendix F: British Columbia

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6. Appendix F: British Columbia Regulatory Framework

The British Columbia Utilities Commission (BCUC) is an independent regulatory agency of the Provincial Government operating under and administering the Utilities Commission Act (UCA). The present composition of the Commission was established in 1996 through the Utilities Commission Act. The BCUC operates as an administrative tribunal, but is often referred to as a “regulatory tribunal” or “quasi-judicial tribunal” because its processes are loosely structured on those of the courts. The Commission's primary responsibility is the regulation of British Columbia's natural gas and electricity utilities. The BCUC reviews and approves rates, return on equity, operation and maintenance expenditures, and capital investments of electricity and natural gas utilities with an underlying principle of procedural fairness.

The Commission is composed of one Chair, two Commissioners, and six Temporary Commissioners. The Commission has jurisdictional functions in imports and exports, generation and production, transmission, distribution, supply, monitoring, settlement, and enforcement. Commission staff is separated into three groups: 1) Information Services; 2) Regulatory Affairs and Planning – split into strategic services, rates and finance, and engineering and commodity markets; and 3) the Office of the Chair and Financial Administration.

The Commission and its staff are responsible for ensuring that customers receive safe, reliable and non-discriminatory energy services at fair rates from the utilities it regulates, that shareholders of these utilities are afforded a reasonable opportunity to earn a fair return on their invested capital, and that the competitive interests of British Columbia businesses are not frustrated.62 It approves the construction of new facilities planned by utilities and their issuance of securities. The Commission's function is quasi-judicial and it has the power to make legally binding rulings. Decisions and Orders of the Commission may be appealed to the Court of Appeal on questions of law or jurisdiction.

The Commission also reviews energy-related matters referred to it by the British Columbia Government Cabinet. These inquiries usually involve public hearings, followed by a report and recommendations to the Cabinet. The Commission recovers its costs from regulated utilities and pipeline companies by fixing a “per gigajoule” on each utility based on total energy sold in the previous calendar year. The Commission was authorized to recover costs beginning in 1988 through the Utilities Commission Act (Section 125) and the Levy Regulation (BC Reg. 283/88).63

The core areas of Commission activity are:

Revenue requirements; Rate design; Capital projects review; Oversight of energy commodity cost and competitive market development;

62 BCUC Website. 63 BCUC Annual Report 2005/2006.


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Safety and reliability; Information service and complaints; and Activities related to the BC Energy Plan.

In addition, the BCUC is a member of the Western Electric Coordinating Council (WECC). WECC is the regional reliability council for the western US and northwest Canada and is responsible for coordinating and promoting electric system reliability. WECC supports efficient competitive power markets, assures open access non-discriminatory transmission for its members, provides a forum for resolving transmission access disputes, and coordinates the operating and planning activities of its members. The major electricity utilities of British Columbia are part of the WECC interconnection system operations. 64

The BCUC is also a participant in the Canadian Association of Members of Public Utility Tribunals (CAMPUT) where regulators explore harmonizing, standardizing, and streamlining regulation within the limits of enabling legislation.65



In the mid 1990s, two British Columbia Commission investigations looked into reforming the British Columbia electricity market to make it more competitive. The initial “Electricity Market Structure Review” in 1994 and 1995 found that that the driving forces for electricity reform, in particular high prices, did not exist in British Columbia. The Commission’s report recommended that British Columbia move forward with increased competition at the wholesale level and real-time pricing.66

The 1997 follow-up investigation was unable to agree on the components of market reform for the province; however, the head of the task force presented his own proposal for phased electricity reform, which included establishing an independent grid operator to improve (wholesale) access for competitive suppliers to the transmission system, allowing non-utility suppliers to sell directly to industrial customers (limited retail access), and setting a portfolio standard to require that a percentage of power generation come from environmentally desirable technologies.67

Since the release of the two Commission reports, some of the suggested reforms have been implemented, including wholesale transmission access, real-time pricing for large customers and retail access for industrial customers. Other proposals, such as the independent grid operator and portfolio standard, were not acted upon.

Historically, electricity generation, transmission and distribution in British Columbia have been almost entirely publicly-owned and Crown-operated. Terms and conditions of third party access (TPA) to the electricity transmission grid were not regulated until 1999 when third-party access to the 64 WECC Website. 65 BCUC Annual Report 2005/2006. 66 BC Government Task Force Report: “Energy for Our Future: A Plan for BC”. 2002. 67 BC Government Task Force Report: “Energy for Our Future: A Plan for BC”. 2002.


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electricity transmission grid began to be regulated by the BCUC, and in 2002 a liberalized wholesale market for electricity was established. Transmission and generation segments are integrated with the only separation occurring in accounting (established in 2003). Vertical integration of electricity supply is the dominant feature of the market with customer choice of electricity supplier prohibited until 2001 when choice of supplier was granted to large consumers. The minimum threshold for customers wishing to choose their supplier is 999 GW. The 999 GW threshold remains in place today. 68

The British Columbia electricity transmission and distribution network is dominated by BC Hydro, which is a commercially-owned Crown operation, and its separate transmission operator, the British Columbia Transmission Corporation(BC Transmission Corporation). BC Hydro serves approximately 95% of the province’s population and 1.7 million customers. The remaining 5% of the population is served by five investor-owned utilities, and six municipal utilities. The BC Transmission Corporation was incorporated in May 2003 as a new Crown company in order to maintain, operate and plan BC Hydro’s transmission assets. The core transmission assets are still owned by BC Hydro but BC Transmission Corporation is completely independent of BC Hydro, with a separate and independent Board of Directors. Part of the BC Transmission Corporation’s role is to ensure open and non-discriminatory access to the British Columbia transmission system for all electricity producers. BC Transmission Corporation is required to provide open transmission access to British Columbia independent power producers to enable access to US wholesale markets. BC Hydro, through its subsidiary, Powerex, buys and sells electricity when it is advantageous to British Columbia’s ratepayers.

The BC Hydro transmission system consists of 18,286 kilometers of transmission lines, operating at voltages from 60 kV to 500 kV. The 500 kV bulk transmission network connects the major generators in the northern and southern Interior regions of the province, with the major load centers in heavily populated southwest British Columbia. Electricity is supplied to the Lower Mainland and Vancouver Island from the Peace River hydroelectric system through Kelly Lake Substation, and from the Columbia River system through Nicola Substation. The relationship between installed generation capacity and electrical demand around the province drives the development and operation of BC Hydro’s bulk transmission system.

Fortis Incorporated, the largest investor-owned utility in British Columbia, operates its own transmission system synchronously with the BC Hydro transmission system (which is operated by the BC Transmission Corporation). In recent years, Fortis has actively acquired additional IOUs operating within British Columbia. British Columbia is also home to a small number of Municipal Utilities. Virtually all British Columbia Municipal Utilities are distribution-only and purchase power from Fortis Inc.

In 2002, the British Columbia Ministry of Energy, Mines, and Petroleum Resources issued the landmark BC Energy Plan. The Plan included four cornerstones: 1) low electricity rates and public ownership of BC Hydro; 2) secure, reliable supply; 3) more private sector opportunities; and 4)

68 OECD International Energy Regulation Database.


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environmental responsibility and no nuclear power sources. Furthermore, the new policy framework strengthened the regulatory mandate of the BCUC and required the Commission to re-evaluate BC Hydro’s revenue requirements and inquire and recommend terms and conditions of British Columbia heritage contracts that are intended to benefit British Columbia rate ratepayers by locking in the value of existing low-cost generation (heritage energy). BC Hydro rates had been frozen from 1996 through 3 March 2003, frozen with no changes or public review. The Energy Plan also called for the Commission to determine future rate changes using performance-based regulation and negotiated settlements. Additional changes included an emphasis on private sector development of new electricity generation with BC Hydro restricted to improvements in existing plants and required BC Hydro distribution to operate as a separate line of business from generation.69

In 2007, a new British Columbia Energy Plan was released. The plan focused on electricity self-sufficiency – the goal is 2016, reliable transmission networks, and the continued public-ownership of BC Hydro and the BC Transmission Corporation. Furthermore, the 2007 Energy Plan clarified that social, environmental, and economic benefits are important components for the BCUC to consider within its regulatory framework.

A smaller market exists in British Columbia for the direct supply of energy (onsite energy), which is exempted from BCUC regulations, and local surplus sales which require independent power producers and industries generating their own energy to receive exemptions from the Provincial Minister or the BCUC (with Cabinet approval) to sell surplus energy to nearby customers in limited amounts.


The British Columbia natural gas industry is characterized by transmission and distribution monopolies with a competitive supply market. The British Columbia natural gas industry is not vertically integrated and transmission and distribution services may or may not be provided by the same company.70 British Columbia exports approximately half of its natural gas production. The BCUC regulates the transmission and distribution of natural gas but does not regulate the competitive market for natural gas: however, it requires utilities to provide quarterly reviews of gas prices and deferral account balances.71 Deferral account mechanisms are intended to smooth changes in utility rates and as a result British Columbia customers pay slightly less when gas prices are high and slightly more when gas prices are low. The BCUC reviews utility gas supply contracting and hedging plans to ensure utilities purchase reliable supply at the lowest cost possible.

In 2002, as a result of the new British Columbia Energy plan, Terasen Gas, the largest gas utility in British Columbia, implemented Commodity Unbundling Service for its commercial customers effective 1 November 2004.72 Terasen provides service to 95% of British Columbia 's natural gas customers, with approximately 920,000 customers in 125 communities. The unbundling program

69 BC Government Task Force Report: “Energy for Our Future: A Plan for BC”. 2002. 70 BCUC Participant’s Guide to BCUC. 2002. 71 BCUC 2005/2006 Annual Report 72 BCUC Annual Report 2007/2008


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allowed commercial customers to select a natural gas supplier other than Terasen Gas on a fixed price contract basis for 5 years.73 Large volume customers have traditionally had access to alternative suppliers and thus, did not need an unbundling provision. The unbundling provision also allowed for natural gas marketers to sell directly to small volume customers with licensing requirements for consumer protection.74

The trend towards a competitive gas industry was reemphasized in the 2007 British Columbia Energy Plan, which listed the pursuit of regulatory and fiscal support for being amongst the most competitive gas jurisdictions as one of its key policy actions.75

6.1.1 Number of Companies76

British Columbia Electricity Transmission

No. of Transmission Companies

System Length Average System Length



3 19,470 6,490 18,000 20

British Columbia Electricity Distribution

No. of Distribution Companies

Line Length Number of Customers

Average Line Length


13 61,550 1,938,353 4,735 149,104

British Columbia Electricity Transmission and Distribution Ownership

Investor-Owned Municipal Crown-Owned

6 6 2

*** IOU Ownership has been consolidated within the past 5 years as Fortis has made several acquisitions and additions to its holdings.

73 BCUC Annual Report 2007/2008 74 BC Government Task Force Report: “Energy for Our Future: A Plan for BC”. 2002. 75 BC Government Task Force Report: “The BC Energy Plan: A Vision for Clean Energy Leadership”. 2007. 76 Source for statistics is the BCUC Annual Report 2007/2008


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British Columbia Natural Gas Utilities

Number of Utilities Utility Type Number of Customers Average Number of Customers

11 Investor-Owned 954,532 86,776


Source: British Columbia Energy Plan 2002


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Major Electric Transmission and Power Generating Facilities

Source: British Columbia Utilities Commission 2007/2008 Annual Report


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BC Hydro Electricity Generation and Transmission

Source: BC Hydro 2008 Annual Report


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Natural Gas and Gas Liquids Utilities

Source: British Columbia Utilities Commission Annual Report 2007/2008


Overview of the Process

The Commission’s regulatory jurisdiction is defined by the Utilities Commission Act, which includes three avenues through which the BCUC assesses utility investment plans. The first avenue is a utility application to the Commission. The second avenue is a generic review by the Commission. The third


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avenue is a complaint filing. Sections 58-64 of the UCA provide the legal authority and power for the Commission to change rates. Within each avenue, there are three different methods with varying levels of complexity and depth that the Commission may deploy. The first method is a traditional public hearing process, the second method is an alternative dispute resolution process in lieu of a public hearing, and the third and most frequently employed method is an alternative resolution process followed by a public hearing.

The Commission has traditionally used a cost of service analysis to regulate utility rates and investment plans; however, the Commission has continued to introduce incentive regulation in the form of performance based regulation.

Utility Application for a Rate Change

The Commission’s review of a utility’s application is conducted in the context of current information regarding the long-term plans of the utility, the utility’s recent approved capital projects, and through public hearings. The Commission examines energy resource alternatives, including demand-side management, identified by a utility in its integrated resource plan, revenue requirements, a fair return to shareholders, and the division of revenue requirement amongst customer classes. The Commission may approve across-the-board rate increases or may pursue a rate design hearing in which the utility may determine revenue requirements by customer type using cost-of-service by customer type as the baseline for revenue requirements. Due to changes in customer mix and costs, the BCUC regards rate design hearings which depend heavily on the revenue to cost ratio as highly variable over long time periods. Due to the complexity of rate making, the process is frequently broken down into separate hearings on revenue requirements, return on equity, and rate design.

Generic Review

The Provincial government may request the Commission (or the Commission itself may decide) to look into a contentious energy issue. For example, a generic public hearing may be initiated to examine the Return on Equity for electric and gas utilities in order to develop a better regulatory practice for return on equity regulation.

Complaints

The Commission generally receives two types of complaints related to electricity and natural gas utilities: 1) filings against regulated utilities by other utilities, individuals or groups; 2) filings by utility customers regarding their bills.

Typical issues include: 1) unsafe or inadequate utility service; 2) unjust, unreasonable, insufficient or discriminatory rates; 3) failure to obtain a certificate of public convenience and necessity; and 4) failure to comply with the Utilities Commission Act, another Act, a Regulation, order, bylaw, or direction made by a regulatory authority.


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Alternative Dispute Resolution

The BCUC has adopted alternative procedures to be used prior to the public hearing in order to improve the effectiveness and efficiency of electricity and natural gas regulation. The Commission uses workshops, pre-hearing conferences, town-hall meetings, and negotiated settlements as alternatives to inquire, assess, and potentially resolve issues related to utility investment plans. The BCUC places significant emphasis on using Negotiated Settlements in assessing utility investment plans. The typical process includes the submission of a particular investment plan to the Commission, followed by a procedural conference held by the Commission to determine the issues and order of issues to resolve. The procedural conference is followed by the submission of written and oral testimony by the applicable utility, contrasting or supporting written and oral testimony by interveners, and eventually a Commission decision on the issues involved.

Hearings

Utility applications or a Commission investigation into a complaint are typically the two drivers for holding a hearing. In addition, the Commission may, on its own motion or by request of the Lieutenant Governor, inquire into matters that are within the scope of the Utilities Commission Act. Written and oral hearings may be held with the potential for a review request by the Lieutenant Governor, although review requests are rare and often lengthy. The length of hearing depends upon a number of factors: the reason for the hearing, the size of the utility applying, and whether or not a negotiate settlement process occurred.

Negotiated Settlement

The BCUC emphasizes the use of negotiated settlements as an alternative dispute resolution process to bring utilities and interveners together to discuss disputed items within a submitted application. The goal of a negotiated settlement is to resolve some or all of the items in the application with Commission staff present throughout the settlement process to move the process forward and to represent the public interest. The process is as follows:

1) Commission publishes initial list of issues for negotiation – Upon receipt of a utility’s application, the Commission will decide which issues should proceed to a negotiated settlement and which issues should proceed to a full hearing.

2) Parameters of negotiation are set – Utilities and registered interveners comment on the initial selection of issues made by the Commission in a pre-hearing conference or (less formally) through written response.

3) Settlement negotiations begin.

4) When participants arrive at a “broadly supported settlement” the utility or Commission staff draft an agreement for participating parties to sign.


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5) Final settlement is present to the Commission for approval – the Commission must accept or reject the settlement package as whole. Rejection means a full hearing into all of the issues. The Commission may single out an issue of concern for participants to renegotiate and agree to; however, if there is no agreement to the change requested, a full hearing will be held on all the issues.

Performance-Based Regulation

In the past, the Commission has used performance based regulation for utilities such as BC Gas and West Kootenay Power.77 The two basic approaches for performance based regulation are a price cap approach and revenue cap approach. Key components of the approach used by the Commission contained some and/or all of the following:

A baseline revenue requirement set by cost category that can be modified for inflation, productivity and other factors in the future;.

The creation of an incentive mechanism such as a sharing account where both customers and shareholders are rewarded for management’s cost reduction measures that realize revenue requirements lower than the modified baseline;

A quality control mechanism to ensure that utilities do not pursue cost savings at the expense of system reliability, safety, customer satisfaction or other measures of quality including energy efficiency; and/or

Demand side management.

The largest natural gas utility network in British Columbia and the largest electricity network in British Columbia have both experienced performance based regulation since the mid 1990s. The Participants Guide to the British Columbia, initially published in 1996 and revised in 2002, addresses the role of performance based regulation and notes that there are two basic approaches: 10 price cap; and 2) revenue cap. The price cap system is noted to be “an early version of the approach”.

The price cap system, in which utility rates are capped several percentage points below the Consumer Price Index, allows the utility to recover a profit on what it might have otherwise spent and sought to recover through customer rates. The danger with the price cap system is the incentive for utilities to potentially cut costs devoted to maintenance or quality of service.78 In 2002, the landmark British Columbia Energy Plan 2002 stated that the “Utilities Commission Act will be amended to focus more on performance-based and results-based negotiation, including negotiated settlements”.79

Overall, the Commission has developed a performance based regulatory approach that contains some and/or all of the following:

A baseline revenue requirement set by cost category that can be modified for inflation, productivity and other factors in the future;

77 BCUC Understanding Utility Regulation. 2002. 78 BC Utilities Commission. “Understanding Utility Regulation: A Participants’ Guide to the BCUC”. Revised: July 11, 2002. 79 Bill Grant. BC Utilities Commission. “Traditional Regulation vs Performance-Based Regulation”. April 2003.


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The creation of an incentive mechanism such as a sharing account where both customers and shareholders are rewarded for management’s cost reduction measures that realize revenue requirements lower than the modified baseline;

A quality control mechanism to ensure that utilities do not pursue cost savings at the expense of system reliability, safety, customer satisfaction or other measures of quality including energy efficiency; and/or

Demand side management.

In 2003, the BCUC published a set of conclusions with CAMPUT regarding the use of performance based regulation in British Columbia:80

PBR enhances regulatory objectives by aligning customer and shareholder objectives; PBR can be designed so that cost control and utility accountability are not

jeopardized; Quality of service is more directly recognized and rewarded; Utilities provide direct incentives for employees; Improves investment potential of mature utilities; Longer review periods reduce regulatory costs and streamline regulatory workload; Periodic oral public hearings are desirable to deal with policy and structural issues

and to establish a new base year; and Price Cap regulation – “light-handed regulation – has little application for energy

utilities because it directly contravenes the intent of the Regulatory Compact and may lead to discriminatory activities that could limit competition.

In April 2008, CAMPUT published a paper entitled “Utility Risk and Financing” that compared the allowed equity risk premiums for Canadian and US utilities. The paper noted that while Canadian risk premiums are increasing, Canadian ROEs/risk premiums remain lower than the US. The presentation included graphs of Fortis BC and Terasen Gas, which showed how performance based regulation in British Columbia have allowed utilities to earn more than the allowed ROE.

80 Bill Grant. BC Utilities Commission. “Traditional Regulation vs Performance-Based Regulation”. April 2003


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Utility Perspectives on Performance Based Regulation

BC Gas (now Terasen Gas which is owned by Fortis BC) operated under some form of PBR since 1994 (Grant 2003). Fortis BC experienced performance based regulation of its electricity business from 1996 to 2004 (the network was owned by Aquila until 2000 when it was acquired by Fortis). Fortis BC concluded in a 2006 assessment of its experience with PBR that ““PBR was not harmful”; although, the utility did submit proposals for streamlining and changing the PBR process.81


The BCUC requires a complex variety of information in assessing utility investment plans. Information requirements vary depending upon the nature of the issues the BCUC intends to regulate. Overall, there is a demonstrable effort by the BCUC to push utilities towards transparency in their investment plans by establishing sophisticated information requirements.

In general, utilities are required to present revenue requirements and rate design in a set of regulatory schedules in applications and in annual public reports. Long-term information requirements are described in utility integrated resource plans (IRP), which include rate base information linked to depreciation and amortization and return on equity and total annual revenue requirements. In the

81 Don Debienne. Fortis BC. “Performance Based Regulation: Streamlining the Process”. May 31, 2006.


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immediate to short-term, the information required for the issuance of certificates of public convenience and necessity offer an opportunity for the Commission to make determinants for new, expanded, or refurbished asset investments by utilities.

For rate regulation, the BCUC uses a “future forecast” methodology to review utility expenditures. Utilities apply for rate increases prospectively for “forecast test year periods” of one, 2, or 3 years. Total revenue requirement is determined by the BCUC and is then divided by annual forecast sales volume for forecasted test year in order to get an average rate a utility may charge. The utility’s rate tariff is amended to adopt the new rate. In determining revenue requirements, the Commission examines the utility’s rate base, and or assets the utility may make a return on. The Commission may disallow certain costs in an application if they are deemed not reasonable or prudent.

Beginning in May 2003, the BCUC began requiring public utilities (i.e., BC Hydro) to file additional information in order to pursue the goals of the 2002 British Columbia Energy Plan. The new policy actions, specifically Policy Action No. which required public utility resource plans for regulatory review, resulted in amendments to the Utilities Commission Act (section 45) in 2003. The subsequent information requirements for public utilities in British Columbia to submit to the BCUC now include:

An anticipated capital expenditures plan over a period specified by the Commission; A plan to meet demand for energy via acquisition and the expenditures required; and A plan to reduce demand for energy and expenditures required for that purpose.

A prime example of the new Commission information requirements is the submission by BC Hydro of an Integrated Electricity Plan (IEP) and Long-Term Acquisition Plan (LTAP) on a 4 year cycle. The IEP provides a 20 year outlook that includes 20 year load resource balance forecasts, resource option analysis to meet future loads with characterization of demand-side and supply side options, alternative resource portfolios, and an examination of cost/risk/social/and environmental in portfolio evaluation. The LTAP is a 10 year plan that covers resource mix, demand-side management, potential future resource options, asset management of power generation (notably Burrard power station), and security of supply.

Source: British Columbia Utilities Commission Decision on BC Hydro’s 2006 IEP and 2006 LTAP


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Additionally, BC Hydro submits a Resource Expenditure and Acquisition Plan (REAP) that details its short-term plans (2-4 years) as part of the Integrated Electricity Plan. The REAP is resolved via a negotiated settlement. A REAP includes the following general items:

Planned capital expenditures on capital projects, resource acquisition, and demand-side management;

Anticipated energy demand; and Utility plan to reduce energy demand of its customers.

In May 2008, the government enacted Bill 15, the Utilities Commission Amendment Act of 2008, which required public utilities to file long-term resource plans with more definitive and specific information regarding demand-side measures and explanations regarding why energy demand is being met with new facilities and purchases and by demand-side measures. 82


The British Columbia Hydro Power Authority (BC Hydro) and British Columbia Transmission Corporation (BCTC) entered into an Asset Management and Maintenance Agreement in May 2003. Article 3 of the Agreement delineated the engagement of BC Transmission Corporation to manage and maintain the Transmission System for BC Hydro. The agreement included recognition that BC Transmission Corporation must “manage and maintain the Transmission System to meet all requirements of the Commission, including requirements relating to safety and reliability, and to manage and maintain the Transmission System to meet any applicable requirements of the Western Electricity Coordinating Council and other applicable industry standards”. Article 3 explicitly lists the following asset management requirements for the BCTC:

Capital Replacement Programs and carrying out capital upgrades and additions; Monitoring and assessing useful life of assets forming part of the transmission

system; Identifying significant operating capacity limitations or constraints and developing

appropriate replacement or refurbishment for such assets; Developing, implementing, and evaluating maintenance plans and programs; Maintaining and inspecting the transmission system; Undertaking corrective maintenance and emergency repairs of the transmission

system; Measuring and analyzing asset management and maintenance results; including the

results of capital investment and maintenance plans and programs; Monitoring, evaluating, and implementing technological advancements and

improvements; Managing contracts with Third Parties that are related to the above asset management

policies;

82 BCUC 2007/2008 Annual Report


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Managing and maintaining the transmission system as a prudent owner of similar assets would, including forward-looking investment and replacement programs to maintain and sustain the transmission system; and

Manage and maintain the transmission system in accordance with Good Utility Practice.

The Agreement also explicitly states that Commission Orders take precedence if there are any inconsistencies regarding performance standards and/or requirements.


The Commission has a number of instruments it may use to assess utility investment plans. The following is a brief description of the relevant regulatory powers:

Extension of Service: The Commission may order a utility to extend service to a community if the utility is deemed responsible for that area as a result of a hearing. Any extension may not substantially increase the rates within the utility’s existing service area.

Certificate of Public Convenience and Necessity (CPCN): The Commission requires that utilities file with the Commission for a CPCN before beginning construction of a new plant or system. The Commission awards certificates based on proof that the new system or extension is in the public interest and necessary for the public’s convenience. The Commission has the direction to decide if a CPCN application is warranted.

Commission Approval for Issue of Securities: Long-term debt or capital stock issued by a utility requires Commission approval.

Consolidation, Amalgamation and Merger: Commission approval is required.

Rate Making: Commission determines through a hearing whether or not the rates charged by a utility are unjust, unreasonable, insufficient, and unduly discriminatory or in violation of the UCA.

Service Contracts: Commission may hold a hearing to investigate whether or not a contract between a utility and a customer is discriminatory, preferential, and unenforceable.

Common Carriers: Interested parties may apply to the Commission to hold a hearing to declare that a person who owns or operates a plant for processing or purchasing fossil fuels or operates a pipeline is a “common carrier” or public utility, and is therefore governed by the UCA.

Electricity Transmission Contract: Commission may use a hearing to decide whether or not an energy supply contract entered into by a utility is in the public interest. The Commission may declare a contract to be unenforceable.


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Complaints: Complaints can be made to the Commission about unsafe or inadequate utility service, unjust, unreasonable, insufficient or discriminatory rates, failure to obtain a CPCN, and failure to comply with the UCA.

Participant Costs: Commission may order participants in a proceeding to pay the costs of another participant or the Commission can pay costs to the participants.


The Utilities Commission Act and the subsequent amendments to the Act form the legal basis for regulation of natural gas and electricity utilities by the British Columbia Utilities Commission. The Act is divided into nine parts: 1) Utilities Commission; 2) repealed; 3) Regulation of Public Utilities; 4) Carriers, Purchasers and Processors; 5) Electricity Transmission; 6) Common Jurisdiction; 7) Decision and Appeals; 8) Offences and Penalties; and 9) General.

Part 3 – Regulation of Public Utilities: Contains 43 distinct sections that describe specific and general regulatory uses of power that the Commission may employ. The following sections are of particular note:

Section 23 states that the Commission has “general supervision of all public utilities and may make orders about:

a) Equipment;

b) Appliances;

c) Safety Devices

d) Extension of works or systems;

e) Filing of rate schedules;

f) Reporting; and

g) Other matters the Commission considers necessary or advisable for the safety, convenience, or service of the public.

Section 45 of the UCA was amended in 2003 to “expand and clarify the planning requirements of utilities and the Commission’s role to review filed plans to determine whether expenditures are in the public interest and whether associated rate changes are necessary and appropriate” (BCUC Resource Planning Guidelines). The additions are as follows:

A Public Utility must file the following plans with the Commission in the form and at the times required by the Commission:


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1. A plan of the capital expenditures the public utility anticipates making over the period specified by the Commission

2. A plan of how the public utility intends to meet the demand for energy and expenditures required for that purpose.

After receipt of a plan filed under the above, the Commission may:

1. Establish a process to review all or part of the plan and to consider the proposed expenditures referred to in the plan

2. Determine that any expenditure referred to in the plan is, or is not at that time, in the interests of persons within British Columbia who receive, or who may receive, service from the public utility

3. Determine the manner in which expenditures referred to in the plan can be recovered in rates.


Timing and Guidelines for the Filing of Information

For the filing of information related to revenue requirements, rate design, certificates of public convenience and necessity, tariffs, and other filing matters, the BCUC has established “timing guidelines” that may broadly be described as requiring 30 days advance filing before the desired effective date, encouraging expedited filings by ensuring completeness and through pre-filing options, and the processing of filings on a first come – first serve basis.

Electricity Supply Contracts

The Commission requires that each electricity supply contract and amendments be filed for approval with the Commission. The Commission relies on the all information it considers necessary to determine if the contract is in the public interest. Recommended filing information includes duration of the contract, rights of renewal and other special provisions, reliability considerations, price and price escalation and alternate sources of supply. The purchaser is required to report annually to the Commission any amendment details to the terms of the contract.

Energy Supply Rules: Gas; Gas Cost Reconciliation Account Guidelines; Negotiated Settlement Process Guidelines; Resource Planning Guidelines; and Retail Markets Downstream of the Utility Meter Guidelines.


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Section 26 of the Utilities Commission Act provides for the Commission to set standards. The Act states that “after a hearing held on the Commission’s own motion or on complaint, the Commission may do one or more of the following:

Determine and set just and reasonable standards, classifications, rules, practices or service to be used by a utility.


The British Columbia Utilities Commission has published a number of guidelines for utilities to utilize towards the “cost-effective delivery of secure and reliable energy services”.


The Resource Planning Guidelines and System Extension Guidelines provide a comprehensive outline to assist utilities.

Resource Planning Guidelines

1) Identification of the planning context and objectives of a resource plan.

2) Development of a range of gross demand forecasts (pre-Demand Side Management).

3) Identification of supply and demand resources.

4) Development of multiple resource portfolios.

5) Evaluation and selection of resource portfolios.

6) Development of an action plan.

7) Stakeholder input.

8) Regulatory input.

9) Consideration of government policy.

10) Regulatory review.


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System Extension Guidelines

The BCUC has published ten guidelines for Utility System Extensions or Extension Tests. The Commission’s recommendations are as follows:

1) Utility system extension evaluations should be based on a discounted cash flow evaluation method that includes all incremental costs and benefits associated with a system extension over a time period that is long enough to determine the full impact of the extension. As a general guiding principle, the costs of system extensions should be allocated to the customers who cause them.

2) Utilities should evaluate extensions from a social perspective using a social discount rate and a utility perspective using a discount rate based on each utility’s cost of capital.

3) Utilities should submit extension tests or information that analyzes system extensions on a disaggregated basis.

4) Accurate system estimates.

5) Cost/Benefit Analysis of:

a) Construction costs of the system extension;

b) Associated incremental system improvement costs;

c) Associated incremental O&M costs;

d) Net costs of connection (cost of connection minus connection fees);

e) Net revenues from system extension; and

f) Reasonable consideration of externalities – for the social perspective evaluation.

6) Full cost recovery of utility connections charges up to the meter including incremental costs (meter cost excluded). Utilities offer options for connection fees to signal the net social costs of less efficient energy use.

7) Include cost of the service connection and revenues to be received from connection charges (unless connection charge recovers all connection costs).

8) Situations where consideration of social costs may lead to contributions by other customers, Commission will review matter further.

9) Viable alternative mechanisms for collecting customer contributions should satisfy the following criteria:


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a) Introduce additional options for financing system extensions;

b) Reduce the incentive for prospective customers to avoid the contribution charge by not applying for connection until after the system extension has been funded and constructed. BCUC recommends all customers who attach within first 5 years should contribute;

c) Reimburse initial contributing customers as additional customers connect; and

d) Minimize risk to the utility and ratepayers.

10) If system extension is close to break-even on the financial cost test, then justification with a preliminary comparative analysis of all feasible alternatives will likely be required. Analysis should include recognition of significant social and/or environmental impacts for each alternative. This information may be filed as part of an annual statement or as part of a CPCN application.


Investment plan requirements occur within the context of the current long-term plans of the utility. Key aspects of investment plans revolve around certificates of public convenience and necessity, rate regulation, return on equity, and rate design. Certificates of Public Convenience and Necessity applications are required for utilities to demonstrate the cost-effectiveness of planned infrastructure investment and that the investment is in the public interest.

Rate regulation must justify revenue requirements associated with the primary costs of operating the utility. Investment plans must plan for the following costs:

Cost to build, operate and maintain the utility’s facilities; Cost to finance debt incurred from building facilities; Depreciation and amortization expenses; Costs of financing debt generally; and Return on shareholder’s equity including the resulting income taxes.

The rate design analysis criteria used by the Commission requires utility investment plans to use the following principles in their submission of rates83:

Simple and understandable to the customer; Cost-based, or tied to actual services provided; Efficient; Stable and predictable; and Non-Discriminatory.

83 BCUC Understanding Utility Regulation. 2002.


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Return on Equity and the Allowable Return on Equity are key components of a utility’s investment plan. The general methodology of the BCUC is to forecast the risk-free rate of long-term Government of Canada Bonds and then determine a specific risk-premium for each energy utility within British Columbia.84 The ROE percentage is the composite of the risk-free and risk-premium percentages. An example of the investment information required from a utility is listed below in the diagram:

Utility Investment Plan Components for determining Return on Equity

Source: British Columbia Utilities Commission

84 BCUC Understanding Utility Regulation. 2002.


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Diagram of BC Hydro Investment Planning and BC Utilities Commission Involvement


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Over the past several years, the BCUC has required increasingly more detailed information about costs and investments from the utilities under its jurisdiction. This trend is anticipated to continue in the future, along with increased focus on future plans in IEP and LTAP documents. Regular updates to the IEP will be needed to reflect changes to policy or circumstances, and resource plans will need to provide more detailed information regarding demand-side measures – as reflected in the Bill 15 amendments to the UCA.