4. Electricity
4.1 Key Issues
The key issues arising from the review of the electricity sector are summarised below.
4.1.1 Generation
The key issue facing the generation sector is whether generation investment is likely to be sufficient to meet New Zealand's needs. The following key factors are relevant:
- Fuel supply uncertainty. The reduced gas supply is having a significant impact on the future generation investment decisions;
- The impact of the Electricity Commission. The introduction of extensive regulatory powers causes uncertainty in the sector, with the potential to impact on investment decisions;
- The introduction of carbon taxes. The carbon tax regime is still uncertain, and in particular the level at which the tax will be set. Investment in generation is being delayed pending further development of the carbon tax regime;
- Emissions: Given the preponderance of hydro generation, the overall level of emissions from electricity generation is relatively low, but is highly sensitive to:
- the choice of fuel supply at existing thermal generation plant; and
- the choice of new generation capacity (hydro, wind, thermal etc.).
- Transmission. Generators are delaying generation investment until certainty is provided on the transmission pricing methodology and in particular who pays for new investment.
4.1.2 Transmission
The transmission system requires investment to expand capacity in certain areas and to replace aged assets. However, barriers to undertaking this investment include the ability to secure construction consents, along with the ongoing debate as to who should pay for the investment.
4.1.3 Distribution
There remains significant uncertainty in the distribution sector as to the form of the thresholds and control regime currently being developed, and how this may impact on future investment. In addition, the role of the Electricity Commission has created further uncertainty.
4.1.4 Government Sustainability Objectives
One of the key principles articulated in the Sustainable Development Programme of Action is decoupling economic growth from pressures on the environment and from growth in energy use. Decoupling could be achieved through changes in the balance of activity in New Zealand (to less energy-intensive activities) or through more efficient (or less wasteful) use in existing activities. The fact that large numbers of consumers and businesses can voluntarily reduce energy consumption in times of need (e.g. during May 2003), would suggest that there ought to be some (but not unlimited) scope for making such reductions permanent. This would both reduce energy demand and save money for energy users.
The general consensus is that more thermal generation capacity is required (although this view is by no means universally held). In determining (via the market, Government intervention or policy) future generation investment, trade-offs exist between:
- Security of supply;
- The costs of energy production; and
- Emissions (depending on type of generation and choice of fuel).
Government activity, through the initiatives around reserve generation and the potential carbon tax, will clearly affect these trade-offs significantly.
4.2 Generation: Current Position
There are four main producers of electricity in the New Zealand market. One is privately owned:
- Contact Energy - formed in 1996 (and subsequently privatised in May 1999) after it was split from the state-owned Electricity Corporation of New Zealand ("ECNZ");
and three are State Owned Enterprises ("SOEs"):
- Mighty River Power;
- Genesis Power; and
- Meridian Energy.
Together these four companies currently produce 81% of New Zealand's electricity.
Figure 1: Market Share of Electricity Generation (GWh) (31 March 2003)
Source: MEDEnergy Data File July 2003
As at 31 March 2003, the total generating capacity for electricity in New Zealand was 8,413MW. The majority of this capacity is hydro (5,245MW) followed by gas (2,187MW) and geothermal (431MW).
Figure 2: Electricity Generation by Fuel Type (GWh) (Year Ended 31 March 2003)
Source: MEDEnergy Data File July 2003
Gas has played an increasing role in the generation of electricity over the past 18 years having grown from being the fuel source for less than 1PJ of electricity to becoming the second most utilised fuel source.
Figure 3: Electricity Generation by Fuel Type (1974 to 2002)
Source: MEDEnergy Data File July 2003
With the decline of the Maui gas field, data for the year ended March 2004 is expected to show some swing from gas to coal-fuelled generation.
Figure 4: Generating Capacity by Fuel Type (MW as at 31 March 2002)
Source: MEDEnergy Data File July 2003
This mix of fuel in Figure 4 above is set to undergo further change as the Maui gas reserves are depleted, the need for reserve thermal plant is again recognised, and as the carbon emissions tax and credits that will accompany the Kyoto protocol, if it is ratified, come into effect. These changes are expected to bring with them price realignments that may alter the optimal mix of generating plant.
4.2.1 Age and Service Quality
Industry evidence suggests that the condition of the present generation assets is reasonable, commensurate with their age, and that asset condition need not be a concern given adequate ongoing capital and operating expenditure. In addition, the age profiles of assets in service are reasonable and no issues arise that cannot be dealt with by the companies, given adequate ongoing capital expenditure.
Hydro assets dominate the mix and in general, so long as these assets are well maintained, the civil engineering components have very long lives. We have no evidence to suggest that there are significant maintenance issues related to these plants, but there are possibilities for increasing the efficiency of generation of some of them incrementally.
We note, however, the output of the hydro assets is dependent upon having adequate water. Similarly, the ability of thermal stations to generate electricity is dependent upon securing adequate fuel supplies.
We address the issue of shortfalls in future fuel supply for generation assets in section 4.3 below.
4.2.2 Efficiency of Use of Inputs by Infrastructure
The efficiency of energy use is primarily relevant to thermal generation and is governed at the generating stage by the choice of fuel and the generation technology.
At present, generating plant efficiencies are typical of the plant installed and are not an issue in the New Zealand context.8 The likely outturn for New Zealand going forward will be critically influenced by the choice of replacement fuel for gas: other domestic gas supplies, LNG, coal or renewables.
During the year ended 31 March 2003, renewable fuels made up approximately 71% of total electricity generated. The remaining 29% consisted of thermal generation using gas and coal. The amount of gas and coal used in the production of electricity was 91.85PJ and 19.1PJ respectively. The year to year balance between renewables and thermal generation can vary considerably depending on the pattern of dry or wet hydro periods.
Cogeneration
New Zealand has a relatively low level of heavy industrialisation, which limits the application of combined heat and power (co-generation) plants other than in certain industries, notably the dairy industry.
Utilisation of Assets
The load factors of generating plant are commensurate with the type of plant installed and the merit order of dispatch.
4.2.3 Emissions
The majority of the emissions produced by electricity generation come from the burning of fossil fuels. Over the past 12 years there has been a general increase in thermal electricity generation, resulting in an increase in emissions over the period.
Figure 5: Total Emissions by Type of Generation (1990-2002)
Source: Energy Greenhouse Gas Emissions 1990-2002
Geothermal generation output has remained relatively constant. The combination of cheap gas and technological advances in gas-fired generation has resulted in increased reliance on thermal generation.
Carbon dioxide is the largest greenhouse emission from electricity generation (52kt/PJ for gas and 91kt/PJ for coal) with other emissions contributing less than 0.5% of the total.
4.3 Future Generation
There is currently a high level of debate ongoing in the electricity sector about the requirements for new generation, covering issues such as types of plant required, fuel selection, location of plant, transmission requirements and installed capacity.
However, there is general agreement that new generation capacity is required to meet New Zealand's demand requirements.
In the following section we consider possible generation options, provide an overview of recently released views on generation investment and the supply and demand gap resulting under each, and summarise the key issues that potential developers of generation have cited as barriers to additional investment in generation.
4.3.1 Current Supply and Demand Position
During the year ended 31 March 2002, electricity consumption was approximately 119PJ. Industrial customers were the largest consumer group (43.8% of total consumption), followed by residential customers (35.2%) and commercial customers (21.0%).
Figure 6: Electricity Consumption by Sector
Source: MEDEnergy Data File July 2003
Consumption by residential customers has grown by 54% from 1975 to 2002, commercial and industrial customers by 174% and 135% respectively. Total consumption has grown by 104%.
The largest users of electricity in the industrial sector were basic non-ferrous metal products (17.9PJ), agriculture, agricultural services and hunting (5.0PJ), log saw milling and timber dressing etc (4.4PJ), and paper and paper products (7.0PJ). The largest commercial users were wholesale and retail trade (7.6PJ), accommodation, cafes and restaurants (3.6PJ) and finance, insurance, property and business services (3.5PJ).
Figure 7: Electricity Consumption by Industry
Source: MEDEnergy Data File July 2003
Average electricity consumption during the year to 31 March 2002 was 8.4MWh per person. Electricity consumption per capita has grown by 60% from 1975 to 2002.
Figure 8: Electricity Consumption per Capita (1972 to 2002)
Source: MEDEnergy Data File July 2003, Statistics New Zealand
Demand Supply Gap
The electricity supply capacity in New Zealand has generally been adequate over the last 20 years other than during short periods (measured in months) of low rainfall - for example 1992, 2001 and 2003. Shortages in dry years highlight the need for adequate thermal power plant capacity to support the predominantly hydropower system. Additionally, the shortages highlighted a market-related issue: the lack of sufficient risk management instruments in the sector.
4.3.2 Generation Options
The Minister of Energy has stated that new developments providing approximately 150MW of electricity per year are required to keep up with economic and population growth.
a) Gas
To summarise, proven gas reserves are likely to be insufficient to maintain gas-fired power generation after the substantial depletion of the Maui field, requiring either development of new gas fields, or a switch in fuel for power generation, or both. Imported LNG may provide a solution for power generation needs but the associated capital costs are high - the need for port facilities and limitations on location are two factors - and its use is likely to lead to risk sharing among the parties involved. LNG may also face significant public perception issues regarding safety.
Irrespective of whether new natural gas fields are developed or whether LNG is imported, the cost of gas as a fuel for power generation is likely to increase materially.
b) Coal
New Zealand has an estimated15 billion tonnes of in-ground coal of which 8.6 billion is judged to be economically recoverable. Only 570 million tonnes or 7% is currently classified as "measurable recoverable" reserves, meaning it has been defined with some accuracy. Coal fired generation, as for gas fired generation, may have operational flexibility over certain renewables, and is less constrained geographically given the relative ease with which coal can be transported. However, coal fired generation does create greater environmental issues.
The introduction of the carbon tax will have a significant impact on New Zealand's generation mix. Carbon taxes can be expected to increase the price of gas and coal, which are the fuels for the majority of the country's hydro-firming generation capacity.
The impact of carbon taxes, if introduced, will be most severely felt by coal-fired thermal generation given its higher carbon content. New Zealand is rich in coal and, as with gas, it is a natural fuel choice for back up generation.
Key Issues for Coal
Burning coal produces almost twice as much carbon dioxide per unit of fuel as gas, making it a more expensive fuel source once carbon taxes are taken into account. Carbon taxes are expected to add between $1.50 and $2.50 per GJ of coal used in thermal generation.
At $25 per tonne, the tax will add around 1.5 to 2 cents per kWh to the costs of coal-fired generation, compared to around 1 cent per kWh to the cost of combined-cycle gas fired generation.
This increase in generation costs will flow through to electricity prices, although it will depend upon how the generation merit order changes as a result of the carbon tax.
Coal also carries a public perception issue of being "dirty", which is likely to result in these plants being located away from population centres, given SOx and NOx emissions. The coal industry is developing technology to reduce the impact of emissions and increase efficiency, such as integrated coal gasification technology.
In section 4.3.4 below, we give consideration to the carbon tax and its impact on generation investment decisions.
c) Renewables
Hydro
New large-scale hydro generation faces significant barriers to development.
For example, if Project Aqua proceeds, it faces significant hurdles with water allocation rights and resource consents. The development of TrustPower's Dobson hydro scheme for example is contingent on access to an ecological reserve and would require legislative changes to the Conservation Act.
Hydro developments require long lead times, both for consenting and for the construction itself.
There is potential for additional incremental efficiency to be gained from existing hydro schemes but the amounts are not expected to be significant. These developments also face similar issues, such as the consenting process and water diversion issues.
Geothermal
New Zealand has further geothermal resources available for development but they have not been sufficiently attractive to date for large-scale commercialisation. During the year ended 31 March 2003, geothermal plant contributed 7% of the electricity produced.
During the late 1950s to early 1980s, the government funded a number of geothermal exploration studies. As a result, 100 unused but potentially productive geothermal wells exist at Wairakei, Tauhara, Rotokawa, Kawerau, Ngatamariki and Ngawha.
Generally geothermal provides strong baseload performance and low emissions, but in addition to the generic barriers to further electricity generation considered in Section 4.3.4 below, there are several geothermal specific issues that need to be addressed.
In many circumstances, there are issues with complicated ownership structures of the fields requiring negotiation, which while geothermal provides lots of potential, has tended to make these projects slow to develop.
These ownership structures often require unique funding structures, which take time to develop. In addition, there are resource consent issues to be overcome, negative public perception associated with potential land subsidence, air quality issues, uncertainty over its status as a renewable resource, and the potential for Treaty of Waitangi claims. Industry experience indicates that these issues can impact development timeframes by up to eight years on some projects.
Geothermal generation is also more risky than other generation developments, as it is often difficult to gain full confidence in the ability of the geothermal field to produce at the required levels. This can impact generation output, as well as increasing the development costs of the fields.
Wind
New Zealand is ideally suited for wind generation with its long coastlines, where sea breezes and lack of natural impediments result in consistent and relatively strong winds throughout the year. The Energy Efficiency and Conservation Authority ("EECA") has produced a publication Review of New Zealand Wind Potential to 2015 which identified 13 general areas where wind developments would be suitable.
A report prepared by East Harbour Management Availabilities and Costs of Renewable Energy for Electricity and Heat ("ACREEH") also examines the potential of wind generation in New Zealand, and assesses the potential of wind generation over the next 15 years to be approximately 23% of electrical consumption in 2002 at costs of up to 10c/kWh.
However, even though New Zealand has very favourable wind sites, currently these projects are commercially risky.
Early carbon credits were allocated to TrustPower (Tararua) and Meridian (Te Apiti) for 5% of the capital cost of developing these projects. However, these amounts are relatively small in proportion to the total capital cost. We understand that on at least one of these projects, investment only proceeded because much of the infrastructure was already in place (such as roading and communications) and the site was already consented.
Wind developments currently face many of the same issues as most other generation developments. We consider these generic barriers in Section 4.3.4. However, wind projects are more likely to face locational issues. Often wind generation is developed on remote sites, partly as a result of good wind resource, but also due to visual and acoustic impacts. This results in issues for accessing transmission networks and associated higher costs of connection.
Biomass
Generation using biomass involves the conversion of organic matter into electricity. Most commonly used biomass for generation include forest processing residues, landfills and sewage.
Electricity generated from landfill sites use the gas emitted from the decomposing organic matter in the landfill. Auckland has landfill generators operating at Redvale, Rosedale and Greenmount.
These developments are generally small in scale, with the ACREEH report projecting the contribution from landfill generators to be approximately 100 GWh/year in 2012 and in a price range of 6-8 c/kWh.
Issues facing biomass are mainly associated with consenting new landfill developments and finding suitable sites.
Distributed Generation
In general terms, distributed generation has the potential to reduce the level of investment required in the transmission system, reduce wholesale price volatility, and minimise dry-year risk shortage situations. However, incremental distributed generation will not obviate the need for further transmission grid investment.
Additional cogeneration is possible for large users, particularly if electricity prices continue to rise.
Some distribution businesses have also indicated a willingness to invest in distributed generation. The Government has recently released a discussion paper, Facilitating Distributed Generation which proposes regulations to provide for the connection of small scale electricity generation to local lines networks.
At this stage, it is too early to assess the impact on distributed generation from any regulatory changes that may arise as a result of this process.
Summary of Other Renewables and Distributed Generation
In our view, it should not be assumed that renewable energy sources such as wind, or distributed generation in its various forms, will obviate the need for investment in large scale connected electricity producing plant, mainly but not exclusively because of their variable availability, smaller scale of production, and higher specific cost.
Compared to fossil fuel generation sources however, some of the renewable resources could be developed in relatively short time frames, and the economics of these projects are likely to be enhanced under a carbon tax regime.
4.3.3 Demand Management/Response
In addition to developing further generation, demand management has a part to play in reducing potential demand and supply gaps. EECA, in their report Exploring Our Untapped Electricity Resource identified significant benefits arising from demand side participation such as enhanced system reliability, reductions in wholesale market prices, improved market efficiency, better risk management solutions for retailers, reduced emissions, greater opportunity for consumers to manage bills and market power mitigation. The report indicated that demand response could deliver a reduction in use of between 250MW and 900MW.
Vector have set up a "demand exchange" which will allow electricity users with some flexibility in electricity usage to offer times when they are able to reduce their usage or switch to their own generation. A large electricity user may be able to pay other users to reduce their load.
Vector estimate that the demand exchange could help New Zealand avoid generating up to 900MW of peak electricity per year. The exchange will help line companies to smooth out peak demand, defer upgrades at bottlenecks on their distribution networks and reduce energy usage when hydro lake levels fall during extended dry periods.
We understand from our discussions that major users tend not to change their behaviour unless they are faced with significant prices, in some cases up to $200/MWh. This is influenced by the ability of these companies to start and stop production processes. In the longer term higher prices may change behaviour, but these prices could also lead companies to consider the cost effectiveness of operating in New Zealand.
4.3.4 Generation Sector Investment Issues
As highlighted above, additional generation capacity for New Zealand is required, both to cover dry-year shortfalls and depending upon the level of future investment and demand, mean year requirements. We understand however that a number of parties are currently delaying investment decisions in the generation sector.
We consider the major impediments to investment below.
Lack of Certainty in Electricity Sector
Our discussions with sector participants indicate that the high level of uncertainty associated with investment is the key driver behind the delayed generation projects. In particular the following uncertainties were consistently raised:
- fuel supply;
- the impact and role of the Electricity Commission ("the Commission");
- the possibility of carbon taxes; and
- grid developments.
These are considered in turn below.
a) Fuel Supply Uncertainty
The most significant issue is uncertainty about the availability of natural gas for electricity generation. Renewable energy sources and distributed generation, whilst making a contribution, are unlikely to obviate the need for additional thermal power generating plant and its accompanying fuel requirements.
Fossil fuels will be required to operate the thermal power plant needed to:
- augment hydropower production during dry periods (hydro firming, particularly in late summer/autumn); and
- provide base load and peaking generation capacity for all years.
In the absence of finding and developing further large reserves of indigenous gas, the most likely future thermal fuels for generation are coal (in the short-medium term) and LNG (longer term).
It is interesting to note the fate of two large baseload gas fired thermal generation projects proposed in recent years.
- Contact Energy obtained consents to develop Otahuhu C, but construction is now on hold due to a lack of secure fuel supplies; and
- Genesis Power plan to have e3p on line in 2006, but secure gas supply remains an issue (Genesis Power's investment in Kupe provides potential reserves, although these are not yet firm).
Gas supply is also dependent, in certain situations, upon open access to the Maui pipeline, for e3p for example. The Maui pipeline is currently available for Maui gas only. Genesis can transport their non-Maui gas to Rotowaro, but transportation from Rotowaro to Huntly requires access to the Maui pipeline unless an alternative pipeline is built.
Other than fossil fuels, access to water (as a "fuel source") is also an issue for planned hydro schemes. A case in point is Project Aqua and whether it can secure sufficient water needed to make the project viable.
b) Electricity Commission
There is a general concern over the lack of certainty around Government energy policy and the stability of the current regulatory regime. The role of the new Commission is still being defined and the recent draft Government Policy Statement ("GPS") is a move towards this.
The Commission's key tasks (as proposed by the Electricity and Gas Industries Bill and the GPS) are to use reasonable endeavours to ensure security of supply, establish a decision making process and transmission pricing methodology for investment in the transmission grid, improving demand side participation in the wholesale market and consumer protection measures. The Commission's role in the electricity industry is however creating current uncertainty in the market as investors wait to see how the market will evolve under the Commission.
Prior to the development of the Commission, the industry was moving towards a market-oriented design but under the Commission it is unclear what type of model will be developed. The draft Government Policy Statement includes a number of statements which suggest that there will be a shift from a market oriented model to one that is more regulated.
Although it is still at an embryonic stage, concerns expressed by industry participants during our consultations focussed on the increasing role of the government in the sector (both as a participant through its control over reserve energy and its relationship or influence over the Commission), the potentially interventionist powers available to the government and Commission, and the influence that the Commission may have on the operating environment of the generators and the potential conflict between this role as regulator, and the Government's ownership of Meridian Energy, Genesis Power, Mighty River Power and Transpower.
The Commission is also responsible for contracting reserve energy. While Government policy has specified the price that would trigger despatch of reserve energy, there is concern that this price may not remain firm. Although a tight ring-fence is to be imposed, it appears that this can be reviewed in three years time (which is likely to have an effect on generators' investment decisions).
Ultimately, these uncertainties have the potential to further delay investment and impact on the cost of capital of the generators.
c) Impact of Carbon Taxes
Incentives to invest in generation are affected by uncertainty about the carbon tax, and in particular what the cost of the carbon tax will be, and whether the Kyoto protocol will come into force.
The carbon tax framework is not yet clear. While the Government has indicated that the carbon tax will be capped at $25 per tonne of CO2, a range of $15 per tonne to $25 per tonne can significantly change generation project economics. There is a big incentive for investors to delay investment in thermal generation, as the option value of waiting is significant.
The carbon tax is likely to have a significant impact on the relative economics of various generation opportunities, and some clarity on the framework under which it will be applied is needed.
Furthermore, funding may be more difficult to arrange, or more expensive, given the uncertainty associated with electricity prices and the carbon tax.
The introduction of a carbon tax is likely to lead to an increase in electricity prices. This will have downstream implications for New Zealand's energy intensive industries, and may have negative national economic consequences, if our relative competitive advantage in cheap fuel sources be eroded.
New Zealand is finely balanced as to whether it will meet its Kyoto requirements, and some generation sources such as coal look unlikely without some reversal of greenhouse gas policy. What energy choices New Zealand will make, such as favouring imported LNG over coal, will depend in part on government policy on meeting Kyoto obligations.
Some industry participants consider that there is a potential for a green bias at the expense of New Zealand's economic welfare, when the real priority is for a reliable infrastructure to underpin growth, which is then supported by policies at the edge to mitigate harmful effects.
It is also interesting to note what the impact of the carbon tax will be for non-emitters, and in particular existing hydro generators who will benefit from increases in wholesale prices (as a result of the marginal priced plant being thermal). This will effectively provide a windfall to those companies that are predominantly hydro-based generators: Meridian Energy, Mighty River Power and Contact Energy.
d) Transmission
Generators are delaying investment decisions until certainty is provided on the transmission pricing methodology and in particular who pays for new investment. Generation projects generally have long lead times and certainty on transmission issues is required before generation investments will be undertaken.
It is imperative that the future direction of the transmission grid is resolved quickly. This should be a priority issue for the Commission. We have addressed issues associated with the need for further development of the transmission grid under Section 4.4.
4.3.4.1 Other Barriers to Generation Investment
Regulation is widely perceived in the industry as impeding appropriate responses to market issues.
a) Resource Management Act
There is a general consensus across the industry that the Resource Management Act ("RMA") is conceptually good legislation. However, it is a time consuming and expensive process due to the level of consultation required. While it does cause some constraints to further infrastructure development, these constraints are not generally seen as insurmountable. In most cases, investment projects have proceeded through the process but it does take time, and has the potential to cause delay. Meridian have highlighted the RMA as a key hurdle for Project Aqua, located on the Waitaki River.
The government has recently announced its intention to make greater use of its "call in" powers, which provides central government with the power to grant resource consents under the RMA to projects that are in the national interest.
The Environment Minister has "called in" applications for consents on the Waitaki River and will introduce special legislation to process all consent applications to use water from the Waitaki River (replacing the RMA).
Criticisms of the RMA include:
- limited strategic vision required for big infrastructure projects, resulting in ad-hoc modifications;
- focus on local over national issues;
- a potential bias toward climate change and efficiency issues; and
- the process can be undermined by small interest groups, who hold out and force large costs on others.
b) Conservation Act
There are a number of generation opportunities that utilise land administered under the Conservation Act (such as TrustPower's proposed hydro scheme near Greymouth). Developments of this nature can be difficult to progress given that the Act is designed to protect conservation values.
c) Legislative and Regulatory Inconsistency
Inconsistencies in policies and applications between regional councils and other regulatory bodies has added to the uncertainties associated with commissioning further geothermal generation. For example, there are different views on its renewable and sustainability status.
Similarly, the Government has set maximum Nitrous Oxide ("NOx") guidelines, but Regional Councils may decide on different levels, leading to inconsistencies across regions, making investment planning more difficult.
These issues, while they may be considered minor on an individual basis, increase the level of uncertainty surrounding future investment.
4.3.5 Generation Forecasts
Having covered the main generation plant options, we now consider potential future generation scenarios.
Three recent publicly available projections of new generation are
- New Zealand Energy Outlook to 2025 ("Energy Outlook") - published by the MED;
- Electricity Supply and Demand to 2015 - Sixth Edition ("ESD") - jointly published by Sinclair Knight Merz and CAE; and
- Power Generation Options for New Zealand ("PGONZ") - published by Sinclair Knight Merz.
We cover the main points from each of these reports below.
a) Energy Outlook to 2025
The Energy Outlook is prepared for the purposes of estimating the future demand for energy to 2025 and the sources that may be used in meeting that demand. It is not, as such, a forecast of generation options, although it does indicate possible generation solutions under various scenarios. Assumptions on the cost of additional electricity generation and capacity to meet forecast levels of demand are shown below.
Table 1: Energy Outlook Assumptions on Generation Options| Generation type | Total cost
(c/kWh) | Potential capacity
(MW) | Potential supply
(GWhpa) | Potential av. Load
(%) |
| Gas Combined Cycle | | | | |
| 2005-2025 | 5.7 to 7.7 | 800 | 5000 | 71 |
| 2008-2025 (incl. C charge) | 6.5 to 8.5 | 800 | 5000 | 71 |
| Wind | | | | |
| 2006-2010 | 6.2 | 190 | 750 | 45 |
| 2011-2020 | 6.2 | 240 | 840 | 40 |
| 2021-2025 | 6.5 | 250 | 750 | 35 |
| Geothermal | | | | |
| 2006-2010 | 4.0 | 25 | 200 | 90 |
| 2011-2020 | 6.2 | 225 | 1800 | 90 |
| 2021-2025 | 6.2 | 380 | 3300 | 90 |
| Project Aqua | | | | |
| Stage 1 (from 2009) | 4.5 | 285 | 1600 | 64 |
| Stage 2 (from 2012) | 4.5 | 285 | 1600 | 64 |
| Other Hydro | | | | |
| Medium cost: 2006-2025 | 7.0 | 50 | 250 | 55 |
| High cost: 2006-2025 | 8.5 | 280 | 1350 | 55 |
| Other Wind | 8.5 | 600 | 1800 | 35 |
| Coal | | | | |
| South Island: | | | | |
| 2005-2025 | 6.1 to 7.1 | very large | very large | 80 |
| 2008-2025 (incl. C charge) | 7.6 to 8.6 | very large | very large | 80 |
| North Island: | | | | |
| 2005-2025 | 8.3 to 9.4 | no limit | no limit | 80 |
| 2008-2025 (incl. C charge) | 9.8 to 10.9 | no limit | no limit | 80 |
| Cogeneration | 4.6 | 350 | 1700 | 55 |
| LNG | | | | |
| 2005-2025 | 8.5 to 10.6 | no limit | no limit | 71 |
| 2008-2025 (incl. C charge) | 9.3 to 11.6 | no limit | no limit | 71 |
| Fuel Oil | | | | |
| 2005-2025 | 11.3 | no limit | no limit | 75 |
| 2008-2025 (incl. C charge) | 12.0 | no limit | no limit | 75 |
| Distillate | | | | |
| 2005-2025 | 16.0 | no limit | no limit | 75 |
| 2008-2025 (incl. C charge) | 17.0 | no limit | no limit | 75 |
Source: MED Energy Outlook 2003
Total new generation capacity required under the reference scenario in 2025 is 3,355MW, with most of this capacity being hydro and gas plants (27% and 24% respectively), while wind and geothermal generation provide 19% each, with the remaining 11% being distillate and cogeneration.
Figure 9: Energy Outlook Projected Sequence of New Generating Plants
Source: MEDEnergy Outlook 2003
Under this scenario, the average new generation capacity from 2001 to 2025 is 139MW per annum. Electricity production is expected to grow at a projected rate of 1.2% pa over the period 2000 to 2025 from 36,900GWh to 49,300GWh.
Figure 10: Energy Outlook Forecast Energy Production under Reference Scenario
Source: MEDEnergy Outlook 2003
The Energy Outlook assumes electricity demand growth at an average of 1.2% per year from 2004 to 2025 (1.2% per year for industrial and commercial customers and 1.1% for residential customers).
The Energy Outlook also considers a number of alternative scenarios, including:
- High GDP - high growth scenario for GDP of 4% from 2007 onwards;
- No new gas discoveries - only Pohokura and Kupe are developed;
- Low energy efficiency uptake - no increase over the present trend of 0.75% p.a.; and
- Continued Methanex operation to 2005.
These alternative scenarios show greater demand for energy and higher resulting costs as more expensive sources of energy are used.
b) Electricity Supply and Demand to 2015 - Sixth Edition ("ESD") (Sinclair Knight Merz and CAE)
The ESD report has modelled three scenarios for new generation plants:
- "baseline" (committed and probable new plant);
- "short term" (stations that could be built or upgraded in a relatively short time frame to mitigate the risk of shortages); and
- "kia mahi tahi tatou" (work together to get a reliable supply of power with the majority coming from renewable sources).
Figure 11: ESD Baseline Scenario New Generation Plant Capacity
Source: Energy Supply and Demand to 2015, Sinclair Knight Merz and CAE
Under the baseline scenario, new generation capacity by 2012 would be 1,079MW and an average of 108MW per annum. Under this scenario, 53% of new plants will be hydro, 37% will be gas plants, 8% will come from geothermal plants and the remaining 1.5% will come from wind generation.
Under the short term scenario, total new generation capacity to 2020 is 1,131MW and new generation to 2012 is 1,011MW. Under this scenario, new coal and oil plants will make up the largest proportion of new generation capacity (74.2% by 2012 and 66.3% by 2020). New hydro plant capacity contributes less than geothermal, gas, wind and coal/oil plants up to 2020.
Figure 12: ESD Short Term Scenario New Generation Plant Capacity
Source: Energy Supply and Demand to 2015, Sinclair Knight Merz and CAE
The final scenario modelled by ESD, shows total new capacity by 2014 of 1,269MW. The kia mahi tahi tatou scenario incorporates known and notional schemes (including all possible schemes) which are technically feasible and environmentally acceptable to most New Zealanders. Most of this new capacity comes from new hydro and geothermal plants (73% and 21% respectively).
Figure 13: ESD Kia Mahi Tahi Scenario New Generation Plant Capacity
Source: Energy Supply and Demand to 2015, Sinclair Knight Merz and CAE
Forecast production of electricity under the Baseline scenario for the period 2004 to 2015 is as follows.
Figure 14: ESD Forecast Generation by Fuel Source
Source: Energy Supply and Demand to 2015, Sinclair Knight Merz and CAE
Total generation is expected to grow between 1.6% to 1.9% per year from 2004 to 2020. The ESD demand forecast for the period 2004 to 2015 is presented below.
Figure 15: ESD Projected Electricity Demand
Source: Energy Supply and Demand to 2015, Sinclair Knight Merz and CAE
Under all three generation scenarios, demand is assumed to grow at a historic rate of 1.8%. No account is made for differences in sectoral growth.
Under the baseline scenario, a shortage in supply is expected 2011 onwards in an average rainfall year. The generation capacity under the baseline scenario would be insufficient in a one in twenty year dry scenario from 2003/2004 onwards.
Figure 16: ESD Forecast Electricity Supply and Demand Baseline Scenario
Source: Energy Supply and Demand to 2015, Sinclair Knight Merz and CAE
The ESD model indicates that under the baseline and short term scenarios demand will be met and generation would provide security against a one in twenty dry year from 2006 to 2009, and mitigate the risk of dry year shortages prior to 2006.
If the kia mahi tahi tatou initiatives are also incorporated, electricity supply will meet demand and provide security against a one in twenty year dry year up to 2015.
c) Power Generation Options for New Zealand
The PGONZ report reviews likely prospects for new generation over the shorter term (next 3 or 4 years) based on publicly available information. The report identifies several hundred megawatts of additional capacity that could be brought online in the next six months by importing new generators to meet demand.
The PGONZ has analysed new generation both including and excluding the potential impacts of the RMA (with the impact of the RMA process factored in as a development time delay).
Figure 17: PGONZ Forecast Capacity from New Generation
Source: Power Generation Options for New Zealand, Sinclair Knight Merz
Figure 18: PGONZ Forecast New Generation
Source: Power Generation Options for New Zealand, Sinclair Knight Merz
Forecast new capacity by 2012 is 3,937MW producing 22,444GWh per annum under both the RMA and no RMA scenario.
By 2012, PGONZ estimates that 43% of new generation capacity will come from thermal generation, 36% from hydro, 15% from geothermal and 6% from biomass and wind generation. The PGONZ report identified 58 potential new generation projects over the next 10 years, two of which were Project Aqua phases.
4.3.5.1 Electricity Generated by Renewable Sources
In the year to 31 March 2003, approximately 71% of the total electricity generated in New Zealand came from renewable energy sources.
The Government has set a target of increasing consumer energy supplied from renewable sources by 30PJ by 2012. Energy supplied by renewables can take the form of electricity or heat. The ESD baseline scenario shows the increase in electricity generated from renewables by 2012 to be 17PJ while the Energy Outlook projections show electricity from renewables by 2012 to be up by 20PJ. Whilst electricity generated from renewables may not meet the 30PJ target on its own, it is expected that 30PJ of energy from renewable sources will be met from a combination of electricity and heat (most of the additional renewable heat is expected to come from geothermal and biomass).
Figure 19: Energy Outlook Projections for Increase in Renewable Energy Supply
Source: Figures derived from projections for hydro, geothermal and wind power from MEDEnergy Outlook 2003
Figure 20: ESD Projections for Renewable Electricity Supply
Source: Electricity Supply and Demand to 2015 - Sixth Edition ("ESD") (Sinclair Knight Merz and CAE)
Generally, renewables are expected to continue to increase in use.
4.3.6 Comparison of Forecasts
The Energy Outlook and ESD forecasts present differing views on whether New Zealand is likely to have adequate generation capacity. Given that the Energy Outlook is designed to indicate which generation sources are likely to be used to meet demand requirements, it indicates no shortage over the forecast period (i.e. additional capacity is built to meet demand as required). By contrast, the ESD indicates shortages occurring from 2009-2010 for a normal year. The main differences are:
- The ESD assumes a loss of water rights.
- Pohokura and Kupe gas comes on line one year later under the Energy Outlook projections.
- No new gas fields are discovered under the ESD projections while the Energy Outlook projections assume that new discoveries occur from 2011 onwards. However, the ESD model assumes that Methanex closes in 2004 making an additional 82PJ of gas available for electricity generation.
- Carbon taxes are not included in ESD model.
- Differences in forecast growth in energy demand.
The PGONZ report has identified 58 potential generation developments over the next 10 years but does not incorporate further analysis on the impact of regulation, cultural and technical factors on investment decisions. The PGONZ report does not provide a forecast of likely new generation but rather presents a view on what is possible over the next 10 years and as a result presents the most optimistic view on generation out of the five studies.
4.3.6.1 Summary of Generation Forecasts
The following table summarises the adequacy of electricity supply under each of the electricity projections in this report.
Table 2: Comparison of Energy Forecasts| Source | | Mean year shortfall | Dry year shortfall |
| Energy Outlook | Base case | No shortages | Not forecast |
| ESD | Base case | 2011 onwards | 2003/2004 onwards |
| Short term | No shortages | 2009 onwards |
| Kia mahi tahi tatou | No shortages | 2016 onwards |
| PGONZ | | No shortage | |
The Energy Outlook indicates potential generation scenarios to meet electricity demand requirements and as such is not a forecast of generation projects. Therefore no shortages are envisaged. The ESD and PGONZ forecasts indicate that New Zealand will have enough generation to adequately meet demand for a normal year, but forecast capacity in the event that hydro generation becomes impaired is not adequate.
4.3.7 Forecast Emissions
There are few forecasts available for emissions from electricity generation. The Energy Outlook provides a high level summary of CO2 emissions over the period to 2025 in the table below.
Table 3: MED Energy Outlook Carbon Emissions Forecast| Calendar Year | KtCO2 |
| 2000 | 6,400 |
| 2005 | 6,900 |
| 2010 | 5,100 |
| 2015 | 5,200 |
| 2020 | 5,500 |
| 2025 | 8,500 |
| Growth pa 2000-2025 | 1.1% |
Source: MEDEnergy Outlook 2003
Emissions from electricity generation increase in the period to 2005 as Huntly power station switches to higher utilisation of coal as its main fuel source. Coal is then replaced in the period to 2010 and onwards by a mixture of additional gas-fired generation and an increasing proportion of renewables. In the final five-year period, carbon emissions increase significantly as gas supplies are projected to tighten and coal is again used more heavily at Huntly.
The baseline generation scenario under the ESD projections shows gas usage for thermal generation declining slowly from 2004, and being replaced by new renewables. However, most of the new demand growth in assumed to be met by coal. Under this scenario, carbon emissions will increase from 2004 onwards.
The critical point highlighted here is the sensitivity of New Zealand's emissions to decisions as to fuel source at a single major power station (Huntly).
4.3.8 Electricity Prices
History
The combination of low gas prices and the abundance of natural waterways, has meant that New Zealanders have enjoyed plentiful electricity supply and one of the lowest electricity prices in the world as noted in the graph below. These attractive energy prices have lead to New Zealand becoming an energy intensive economy.
Figure 21: International Comparison of Industrial Users' Electricity Prices (Q4 2002)
Source: Energy Data File July 2003
Figure 22: International Comparison of Residential Users' Electricity Prices (Q4 2002)
Source: Energy Data File July 2003
The following graphs show the average annual charge for electricity by residential, commercial and industrial consumer groups.
Figure 23: New Zealand Electricity Consumer Prices
Source: Energy Data File July 2003
Real electricity prices for commercial consumers have fallen by 51% between 1979 and 2002, while industrial consumers have experienced a fall of 12% over the same period. Electricity prices for residential consumers have increased by 31% between 1979 and 2002. This arises partly as a result of the reduction of cross-subsidies.
Recent volatility in wholesale prices is causing concern for consumers, particularly with the linking of some retail prices in the commercial and industrial sectors to the market's wholesale spot price. This volatility should be reduced once the appropriate measures have been taken by the Electricity Commission to mitigate dry-year supply risk.
The Market
Wholesale electricity market participants consist of generators, retailers and large industrial players who trade at 244 nodal points across the transmission network. The market is currently governed by a set of multilateral contracts known as NZEM, MARIA and MACQS (which is not operational) and by bilateral contracts between Transpower and its customers. These governance arrangements will shortly be replaced by electricity governance regulations and rules.
Figure 24: New Zealand Average Monthly Wholesale Electricity Price
Source: NZEM
Tight water levels during the 2001 and 2003 winters resulted in large spikes in average monthly wholesale prices (peaking at $231.60 per MWh in 2001 and $201.80 per MWh in 2003). Volatility of the wholesale electricity prices has ranged between 9.33 and 14.87 standard deviations per year (excluding 2001 and 2003).
Table 4: Volatility of New Zealand Wholesale Electricity Prices ($/MWh) | Oct 1996 to Sept 1997 | Oct 1997 to Sept 1998 | Oct 1998 to Sept 1999 | Oct 1999 to Sept 2000 | Oct 2000 to Sept 2001 | Oct 2001 to Sept 2002 | Oct 2002 to Sept 2003 |
| Mean | 44.63 | 36.42 | 37.03 | 32.42 | 7873 | 40.25 | 83.17 |
| Std Dev | 9.33 | 3.66 | 14.57 | 9.49 | 61.19 | 14.87 | 55.31 |
Source: NZEM
Recent shortages highlighted that while the wholesale electricity market is providing pricing signals, these signals are not necessarily acted on in a timely manner. There is increasing evidence of demand response to price during contingency events. Sinclair Knight Merz and the Centre for Advanced Engineering in their report Electricity Supply and Demand to 2015 indicate that recent experience has shown that prices for major users need to increase by 5 to 10 times in the short term before demand is reduced (primarily as we would expect major users to be committed to given levels of output, which may require absorption of substantial increases in power prices). Market-based risk management tools may offer the opportunity for better planning and responsiveness across the market, and lower volatility.
Future Position
Electricity prices are expected to be higher than those previously enjoyed although volatility should be reduced once the Electricity Commission implements measures to mitigate dry-year supply risk. The Energy Outlook forecasts electricity prices under its reference or base scenario as follows:
Figure 25: Forecast Electricity Prices (MED Energy Outlook)
The biggest determinants for electricity prices going forward are likely to be the cost of accessing new thermal energy sources (either coal or gas, locally produced or imported) and the level at which carbon taxes will be set. The Energy Outlook has assumed that the carbon taxes will be set at $15/ tCO2 and will be introduced from 2008 onwards.
Infratil has estimated the cost of coal-fired generation to increase from just under 6c/kWh to between 7.2c/kWh to 7.5c/kWh, with the imposition of an emissions tax of $15/tCO2.
Meridian has estimated the price of electricity for Project Aqua to be 4.5c/kWh excluding the cost of connection to Transpower (i.e. at source). Infratil has estimated this to be between 6.5c/kWh to 7.5c/kWh if the cost of dry year back up is also accounted for.
TrustPower has indicated that wind is commercially viable at wholesale electricity prices of between 6.5c/kWh to 7.0c/kWh.
The new generation projects identified in the PGONZ report shows that approximately 61% of its projects can produce electricity in the 6-7c/kWh range.
The ACREEH report examined the cost of producing electricity using renewable sources. Their cost estimates show that the cost of electricity using renewable energy sources other than hydro would be 6-8c/kWh (2002 cents).
In summary, there is a consensus that prices will increase and that the magnitude of this increase will be determined primarily by the future supply mix, fuel source and carbon tax.
4.4 Transmission: Current Position
Transpower owns and operates New Zealand's transmission grid. The national grid connects the power stations owned by generating companies to substations feeding the local networks that distribute electricity to distribution businesses and direct supply customers.
The core of the national grid is the 220kV system in each island and the HVDC link between them.
The HVDC link, originally commissioned in 1965, now operates at 350kV and 270kV with a capacity of 1040MW. The HVDC facilities include converter stations at Benmore and Haywards, DC transmission lines and three submarine cables across Cook Strait.
The transmission system has come under increasing pressure over the last decade as demand has grown but insufficient system augmentation has been undertaken.
Maps of the Transpower system are provided on the following pages.
Figure 26: Transpower Transmission Network: North Island
→ Larger Version of Figure 26 [151KB GIF]
Figure 27: Transpower Transmission Network: South Island
→ Larger Version of Figure 27 [129KB GIF]
4.5 Transmission: Future Position
Regardless of the actual rate of demand growth, investment in the transmission grid will be required to expand capacity in certain areas and to replace aged assets.
The principal areas requiring reinforcement are:
- transmission capacity into and north of Auckland, from the Waitaki Valley to Christchurch, and from the central North Island to Auckland, as well as other regional investment; and
- replacement requirements (including the older and lower-voltage No 1 pole of the HVDC link).
Transpower has estimated that total grid investment requirements over the next ten years is around $1 to $1.5 billion.
A major constraint to this investment is the ability to secure construction consents generally and line routes in particular, given the limited rights to alter the current use of existing overhead line routes. New installations will be made in accordance with prevailing requirements including those of the Resource Management Act and of the territorial local authorities concerned. The limitations of these on development works generally and on infrastructure development in particular have been debated widely and are well recognised. These processes create delays in development of all types and the securing of new overhead line routes in particular.
Since the lead-time for construction of transmission grid extensions (particularly given the need to secure line routes noted above) is now likely to be longer than that for construction of combined-cycle or other types of quickly-built generating plant, grid augmentation is likely to be on the critical path to increased generating capacity and delivery. The long lead-time also has potential to impact on security of supply.
This, along with the ongoing debate as to who should pay for the investment, and under what pricing methodology, is a critical issue for the generators, Transpower and the distributors, and will be a major challenge for the Commission to resolve.
Views across the industry differ on whether the full transmission grid needs upgrading, or whether better outcomes can be achieved through optimally locating new generation. However, development of distributed generation or attempts to strategically locate investment based on maximising usage of the transmission network will not obviate the need for transmission and distribution system investment.
4.5.1 Transmission Efficiency
Transmission losses as a percentage of energy entering the Transpower system for the last five years are shown below.
Table 5: Transmission System Losses| Year Ended 30 June | 1998 | 1999 | 2000 | 2001 | 2002 |
| Loss Ratio | 4.3% | 3.8% | 4.0% | 4.7% | 2.9% |
Source: Transpower
There is further scope for greater transmission efficiencies through the proposed development of a 400kV grid, or the introduction of new technologies, particularly superconductors (superconducting transformers are in prototype development; superconducting cables are a rather more distant possibility). Where the introduction of new technology offers an evident overall financial gain for infrastructure owners, it can be expected to be introduced over time.
4.6 Distribution: Current Position
Electricity is delivered to end users by 28 electricity lines businesses ("ELBs") from Transpower's grid exit points.
The following table summarises the relevant data for each ELB.
Table 6: Electricity Lines Business Key Characteristics| Electricity Line Business Statistics (year end 31 March 2003) | 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 Lines* | 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 |
| Vector | 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 |
Source: 2003 Information Disclosure Gazettes
There is an enormous divergence across the distribution sector, with Vector making up one third of the sector (by number of connections) and the largest four (Vector, Powerco, Orion and Unison) supplying 66% of all connections.
The location of each distributor is shown in the following figure.
Figure 28: Map of Electricity Distributors
Source: PricewaterhouseCoopers
- Top Energy
- Northpower
- VECTOR
- Counties Power
- WEL Networks
- Waipa Networks
- The Lines Company
- Horizon Energy Distribution
- Eastland Network
- Unison Networks
- Powerco
- Centralines
- ScanPOWER
- Electra
- Nelson Electricity
- Buller Electricity
- Network Tasman
- Marlborough Lines
- Westpower
- MainPower New Zealand
- Orion New Zealand
- Electricity Ashburton
- Alpine Energy
- Network Waitaki
- Dunedin Electricity
- Otago Power
- The Power Company
- Electricity Invercargill
4.6.1 Age of Assets
Figure 29: Percentage Remaining Life of Network Assets
Source: Information Disclosure Gazettes
With the exception of Alpine Energy, Aurora, Eastland, OtagoNet and The Lines Company, all networks report an average remaining life of their network assets in excess of 50%, although most fall between 50% and 60%. Industry evidence suggests that the condition of the present assets is reasonable and commensurate with their age.
4.6.2 Reliability and Performance Indicators
Electrical losses for electricity distribution are 1,378GWh or 5.4% of total electricity conveyed for the 2003 March financial year. It should be noted that losses vary across networks, which is indicative of the wide variety of conditions in which New Zealand networks operate. Generally losses match international experience.
Service quality measures are disclosed annually for System Average Interruption Duration Index ("SAIDI"), System Average Interruption Frequency Index ("SAIFI"), Customer Average Interruption Duration Index ("CAIDI") and faults per 100 km. SAIDI measures the average duration of interruption minutes that a customer on the network experiences. SAIFI measures the average number of times a customer has been inconvenienced by interruption to service. CAIDI measure the average number of minutes lost by a customer affected by an outage. Outages can be planned or unplanned events that originate on a distribution network, or from transmission or generation events.
Recent trends in the median SAIDI, SAIFI and CAIDI are shown below. SAIDI and CAIDI results are highly sensitive to extreme climatic events such as wind or snow storms.
Figure 30: Historical Median System Average Interruption Duration Index
Source: Information Disclosure Gazettes
Figure 31: Historical Median System Average Interruption Frequency Index
Source: Information Disclosure Gazettes
Figure 32: Historical Median Customer Average Interruption Duration Index
Source: Information Disclosure Gazettes
Between 1995 and 2003, the median SAIDI and SAIFI have reduced by 16% and 38% respectively. The median CAIDI during the 2003 year was 68 which is higher than the 1995 median of 64.
Figure 33: Electricity Lines Businesses Faults per 100km
Source: Information Disclosure Gazettes
Distribution network performance is generally reasonable when measured by internationally accepted indicators such as the number of low-voltage complaints, quality of wave-form, absence of harmonics.
4.7 Distribution: Future Position
Investment in distribution system augmentation is required, including the replacement of assets, to meet growing demand whilst maintaining reliability, quality of supply and electrical losses on the networks at reasonable levels. Demand growth varies considerably across the country as demonstrated in the following table.
Table 7: Change in Electricity Demand (2000-2002) | Percentage Change 2000-2002 |
| Maximum Demand | Electricity Supplied | Connections |
| Alpine Energy | 13.1% | 11.7% | 2.0% |
| Aurora Energy | 9.3% | 3.8% | 2.8% |
| Buller Electricity | -46.5% | -55.8% | -3.1% |
| Centralines | 10.1% | 10.3% | -0.3% |
| Counties Power | 14.2% | 5.7% | 1.1% |
| Eastland Network | 4.8% | 6.3% | 7.8% |
| Electra | 5.5% | 5.2% | 4.5% |
| Electricity Ashburton | 19.5% | 18.1% | 5.2% |
| Electricity Invercargill | 16.4% | 4.5% | 0.7% |
| Horizon Energy Distribution | -11.2% | 3.0% | 0.1% |
| MainPower New Zealand | 0.2% | 8.0% | 3.8% |
| Marlborough Lines | 5.0% | 5.8% | 2.3% |
| Nelson Electricity | 8.0% | 2.1% | 1.2% |
| Network Tasman | 6.0% | 5.9% | 3.5% |
| Network Waitaki | -1.9% | 0.1% | -0.6% |
| Northpower | 0.6% | 1.6% | 4.6% |
| Orion New Zealand | 4.3% | 6.1% | 3.6% |
| Otago Power | 7.1% | 11.7% | 1.4% |
| Powerco | n/a | n/a | n/a |
| Scanpower | 3.4% | 4.2% | -0.9% |
| The Lines Company | 15.0% | 0.3% | 1.8% |
| The Power Company | 16.9% | 14.8% | 5.0% |
| Top Energy | 11.5% | 12.0% | 5.2% |
| Unison Networks | 9.3% | 4.7% | 2.6% |
| United Networks | 2.2% | 4.9% | 5.2% |
| Vector | 10.5% | 10.4% | 5.6% |
| Waipa Networks | 0.5% | 9.0% | 2.4% |
| WEL Networks | 1.6% | -0.7% | 3.9% |
| Westpower | 4.3% | 0.8% | 2.9% |
Source: Electricity Information Disclosure Gazettes
As demonstrated above, distributors who have experienced the strongest recent growth in maximum demand and throughput are Electricity Ashburton, The Power Company, Top Energy, Vector, Alpine Energy and Centralines. Others, such as WEL Networks, Northpower and Network Waitaki have shown very little growth and Buller Electricity a decline.
As a result, lines businesses such as Electricity Ashburton and Vector have undertaken considerable expenditure in recent years to augment their systems. Others, such as Network Tasman are about to embark on major investment programmes.
Of particular note has been the demand for additional capacity in the South Island to meet irrigation demand for the agricultural sector and for the high economic growth centred in Queenstown and Central Otago.
As an indicator of the investment required by the distribution line businesses over the period to 2010, Wilson Cook & Co have undertaken an analysis of expected future capacity growth and the cost of meeting both it and asset replacement requirements, based on projected long-term averages. Assuming an annual increase in peak demand of 1.6% and an efficient level of asset utilisation, the incremental capacity required on the distribution networks by 2010 is estimated to be between 1,050 MVA and 1,550 MVA. Including the cost of replacing aged assets the estimated investment requirement is between $1.7 billion and $2.5 billion in current dollars over the period to 2010.
The Commerce Commission is currently developing and implementing a regulatory regime to monitor, and if necessary control, distributor performance, particularly in respect of prices for line services and the quality of services delivered. This process has been underway for the past two years and although it is not yet complete, it is anticipated that it will provide incentives for ELBs to reduce prices to consumers without compromising quality.
There remains some uncertainty for the distribution sector about the thresholds and control regime, particularly the process and response of the Commerce Commission should an ELB wish to increase prices in order to fund investment requirements. This has the potential, in some circumstances, to delay investment or maintenance should ELBs wish to avoid a detailed price control investigation by the Commerce Commission.
In addition, the recent draft GPS, and establishment of the Electricity Commission has created further uncertainty for the distribution sector. In particular, the respective roles of the two Commissions appear to overlap and there may be some jurisdictional issues to resolve, such as price setting. We understand that the Commissions have been directed to develop a Memorandum of Understanding on how they propose to address and operationalise the jurisdictional separation.
Distribution businesses face other barriers to undertaking additional investment on their networks. Our industry consultation has highlighted particular issues associated with local planning requirements. Utility corridors are becoming more and more congested and limitations imposed by local authorities, on working within the corridors is becoming restrictive. These restrictions make it increasingly difficult to undertake new investment and reinforcement efficiently. These issues may extend to Transit for major road corridors.
Another issue facing lines business is the availability of skilled labour. An independent study by the University of Waikato (Is There a Skill Gap? Long Term Planning and Strategy for Effective Training in the Electricity Supply Industry, University of Waikato, August 2003) indicates a growing skill gap. Changes in work practices and efficiency gains achieved by the industry over the past decade have allowed growth demands to be met by the existing workforce. There has been little focus on developing new staff as requirements for additional skilled resource has been limited. The capacity is now more fully utilised and additional resources are projected to be required in the short to medium term. In addition, line business staff (particularly live line staff) have been lured from the local industry for jobs in other countries (notably Ireland), for significantly higher salaries. While we note that this issue has been recognised by the industry and is being acted on, recruiting and training technical staff remains time consuming and costly. As there is a significant lead time to train skilled staff, this may pose a constraint on distributors being able to meet their investment needs in a timely and cost effective manner.
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