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Transitional Measures: Options to Move Towards Low Emissions Electricity and Stationary Energy Supply and to Facilitate a Transition to Greenhouse Gas Pricing in the Future

1. Foreword

2 Executive Summary

3 Introduction

4 Context, Objectives and Scope

5 Policy Options

6 Summary for Discussion

5 Policy Options continued

5.4 Incentives

Other countries have used a number of mechanisms to subsidise investments in renewables capacity. These include capital grants; capacity bidding (for example the Non Fossil Fuel Obligation (NFFO) in the UK from 1990 to 1998) which includes a competitive element, and specified payments per kWh generated for additional capacity (for example, feed-in tariffs). Subsidy equivalents can also be provided in the form of tax deductions or accelerated depreciation.

5.4.1 Capacity grants and subsidies

Capacity subsidies are relatively straightforward in conception, if not in implementation. The government pays the firm or generator enough (or more than enough) in the form of a tax incentive or direct payment to ensure new capacity is installed. The subsidy could be paid in one lump sum or over time, once the generation plant was operating.

Once installed, as a result of a capacity subsidy, the renewables would be expected to operate in the market in an efficient way. Renewable energy-generating plants should have low variable costs of electricity generation, providing that financing repayments are low or zero (and excepting specially-grown biomass, such as energy crops which have ongoing costs). This should have an impact on market prices, pushing lower-cost plants to the margin in all time periods.

The amount of subsidy paid would depend on the competitiveness of bids to supply capacity, how many bidders there are, what the total amount of subsidy is available, the market expectations of future electricity prices and the expectation of future technology prices. As the government would bear some of the risk – such as decisions on other instruments to tackle greenhouse gas emissions – the government might choose to fund some elements of capacity may be consistent with optimal risk-bearing. The main approaches are:

• Published quantities of subsidy that could be provided, such as $per kW of capacity installed (including equivalent tax measures and reduced depreciation). The risk of this approach would be not discovering or stimulating lower bids or smaller levels of tax incentive. There would also be risks regarding the total amount that would have to be paid out if no limit was set on the total capacity that might be funded.

• Bidding. The only risk of this approach would be if the government announced in advance that it would purchase a given amount. If it retained all options, it could choose whether to purchase and how much to purchase solely on the basis of price offered. In this case, it would be important that there were effective penalties for non-installation of awarded contracts. If the penalty was not effective, bidders would have no incentive to bid in ‘real’ prices per kWh or per kW installed.

Evaluation

Environmental effectiveness

The definition that is used in this paper to assess environmental effectiveness is the extent to which a measure is reducing environmental emissions beyond BAU. A general discussion of this definition and how it can apply to a renewable energy support scheme occurred in section 5.3 and is not repeated here.

In general, a well designed renewable capacity bidding system could be expected to deliver more renewables than BAU, although probably less than the feed-in measure discussed later. The amount installed would directly relate to the amount of subsidy available.

Cost effectiveness

From an efficiency point of view, there are three issues of concern:

• whether the instrument can operate to achieve new investment in capacity at least cost

• the effects of how it is paid for

• the effects on electricity prices.

The ability to achieve increased capacity at least cost will depend on the approach used and, in particular, on whether the subsidies are paid out to all renewables, regardless of type, or if they are specifically targeted at wind, hydro, geothermal etc. Providing equal opportunity to all types is the least-cost approach and will lead to the cheapest technologies being developed. However, this approach will not provide support for a diversity of options. Capital grants and a banded capacity bidding system are able to provide support for a diversity of technologies but imply higher payments for certain technology capacity. These measures may be considered cost effective if support for new supply options is an important feature of a renewable support programme.

The bidding system can be designed to either pay just what is required to achieve more renewable entry, or to reward all renewables the same amount, regardless of what is required to achieve entry. The first two rounds of the UK’s NFFO started off with the latter design and then moved to the former.

Bidding systems usually incorporate a competitive element in the bidding process. However, once a contract is awarded, the measure works in parallel to the electricity market rather than as part of it. This is because there is an obligation on the electricity companies to buy electricity at the bid price. This is similar to the feed-in mechanism.

Impact on energy prices

A capacity subsidy does not change the input or output prices directly, but can change total system prices. Any measures that increase the total renewables capacity in the electricity market will shift the supply curve for fossil fuel fuels (those with variable costs greater than zero or thereabouts) to the right, reducing marginal electricity prices. This is not an inefficient outcome in the short run, as resources will not be used in a market that values them at less than their costs of supply.

The total costs of the capital grants are not usually large enough to affect prices. Capacity grants are usually given by government programmes and paid for from tax, which implies that an annual maximum cost is known. Capacity bidding systems also enable the maximum annual cost to be known. How they are paid for differs. In the case of the NFFO, electricity companies were required to buy the electricity at a set price and then invoiced Ofgem, the energy regulator, which reimbursed them from government funds obtained from the general tax revenue. In this situation, the price of electricity would not increase. The cost of bidding systems could be passed on to consumers through their electricity bills. As with obligations, the impact on energy prices would depend on how much generation or capacity was subsidised and how much it was paid relative to the conventional electricity it displaced.

Ease of implementation

Capacity subsidies are relatively simple to introduce. Capital grants may not require new legislation, while a capacity bidding system is likely to require new or amended legislation.

The capacity bidding system would require the government to announce a desire for new renewable capacity and be willing to provide funding for it. Firms would be invited to bid and the government would select bids based on price and quantity. The design of the bidding system would have to be considered carefully.

When the NFFO was introduced in the UK competition was strong, and with limited subsidy funds and no penalties, bidders had an incentive to bid low prices. This increased their chances of being awarded a contract, and meant there was no penalty if they did not develop the project – as turned out to be the case for most of the projects in the latter bidding rounds. However, if the rules removed these incentives, a capacity bidding system would be similar to a feed-in tariff but with a competitive element and a quantified maximum annual cost to the government.[C. Mitchell, The Non-Fossil Fuel Obligation, Energy Policy, 1995; and C. Mitchell, The Non-Fossil Fuel Obligation and its Future, Annual Review of Energy and Environment, 2000.]

Alternative approaches would include published subsidy values, such as $x per MW up to a maximum capacity or dollar amount. This would require a more detailed analysis of costs of new technologies and the likely bids at different levels, or simply an understanding of the government’s willingness to pay based on some other criterion, such as $/tonne of CO₂ reduced.

Capacity grants can be open to abuse if there is not a clear incentive to maximise generation. Without such an incentive or penalty, grants may be given for installation rather than generation output. In addition, while grants should be given to take account of New Zealand costs, it is also important that they are linked to international capacity costs so that grants are not given for inflated costs.

Compatibility with a long-term price on greenhouse gas emissions

Capital subsidies can be compatible with a long-run measure. They provide payments to ensure investments are made in new capacity, although they are likely to lead to a reduction in electricity prices.

Under long-run price measures it would be expected that electricity prices would rise, reflecting an emissions price expressed in the market. This would result in greater returns to investment in renewable capacity built in response to a capital subsidy.

5.4.2 Guaranteed prices/Feed-in tariffs

A wide range of countries used a feed-in tariff as a subsidy to providing a guaranteed price for electricity generation from renewables. Feed-in tariffs involve requiring electricity distributors or suppliers, depending on the country, to buy all renewable electricity offered to them at set prices. These prices differ for different types of generation (electricity from wind, electricity from photovoltaics, and so on). Feed-in tariffs are able to support a diverse set of technologies, including the more expensive, immature technologies. For investors, it is a very low risk mechanism.

Feed-in mechanisms attract a wide diversity of investors, including new entrants who range from traditional energy companies to communities and individuals. This in turn enables heat and power plants of all sizes to be supported from domestic-scale distributed generation or small-scale wind farms through to large-scale wind farms or biomass CHP plants. In addition, new entrants may develop different projects from traditional energy companies, stimulating innovation and diversifying the supply options.

In Germany, the feed-in tariffs were defined initially as a percentage of the average retail electricity price (90 percent for wind, 80 percent for biomass, 65 percent for landfill gas). These percentages were fixed annually by the regulatory authority and paid by retailers. From 2000, the system changed to a payment by the grid operator and for payments to be of a fixed amount, specified in cents per kWh. The amount paid is specified at a rate sufficient to ensure investment, taking account of the costs of installation and expected load factors. It means that the amount paid per kWh differs with the renewable type: more is paid for offshore wind than on-shore wind. Contracts last for 20 years and there is a built-in reducing payment to take account of technological improvement. There are also rules ensuring connection to the nearest point of the distribution grid and specifying how the connection is to be charged. The overall cost of the scheme, which is no more per kWh than the renewable obligation in the UK for the equivalent technologies, is shared equally across customers. However, Germany pays a high price per kWh for photovoltaics and has recently moved ahead of Japan for domestic installation and MW sales.[Total Photovoltaic Power Installed in IEA PVPS available from http://www.oja-services.nl/iea-pvps/isr/22.htm.]

The feed-in tariffs have been particularly successful in Germany and Spain for a diverse set of technologies. Germany added 1,808 MW of wind energy in 2005 to take total capacity installation to 18,428 MW. Spain added 1,764 MW of wind energy in 2005, taking it to 10,027 MW.[Wind Power Installed in Europe, European Wind Energy Association website, available on www.ewea.com.]

Germany used price to introduce particular types of renewable technologies, including photovoltaic energy. Spain has done the same but has also designed the mechanism to have more integration with the electricity market. A similar approach could be taken in New Zealand with, for example, marine energy.

Evaluation

Environmental effectiveness

In general, a well designed feed-in measure can be expected to deliver more renewables than business as usual, and probably more than other types of renewable energy support measure.

Feed-in tariffs are designed specifically to deliver renewable energy. Feed in tariffs have been demonstrated to be effective in terms of delivery of installed capacity. Feed-in tariffs can provide incentives for all types of renewables, of all sizes.

Cost effectiveness

The European Commission (EC) has recently reviewed the renewable energy policies of all the member states.[Commission of the European Communities, The Support of Electricity from Renewable Energy Sources, December 2005, page 42.] The EC review found that feed-in tariffs across Europe are generally no more expensive per kWh than obligation measures. Some feed-in tariffs have been unsuccessful in delivering capacity because their payment is too low. However, the total cost of a feed-in tariff measure can be high because of its success. Germany and Spain may not pay more per kWh for each unit of wind energy, but because they have both installed nearly two GW of wind energy in the last year – compared for example to the UK, which has installed less than that since 1990[Above n 16] – their total cost is relatively more. Even so, the German feed-in has raised the price of electricity to customers by only three percent, and given considerably more capacity.[Volker Oschmann, The German Renewable Energy Sources Act – Objectives, Design and Achievements; and What Electricity From Renewable Energies Cost, February 2006, available from Federal Ministry for the Environment, Nature Conservation and Nuclear Safety on www.erneuerbare-energien.de.]

Impact on energy prices

In theory, a subsidy to new entrants on an output basis would result in additional new entry and no upward impact on electricity prices. Instead, prices would fall because of the shift in the supply curve. In practice electricity consumers may pay for the scheme through their electricity bills.

Ease of implementation

A feed-in tariff system would require:

• a payment mechanism. This might be in the form of a contract between the new entrant generator and the government, but is more likely to require an amendment to existing legislation or new legislation

• a payment method, e.g. guaranteed total price.

New legislation may not be needed if a feed-in tariff system was developed as a contract between the generator and the government. However, this is likely to be cumbersome for the government and it introduces another step in the process, as the generator also has to deal with the electricity distributor in order to connect and generate. Introducing new or amended legislation imposing the feed-in requirements on electricity companies would be administratively simpler, reducing the process steps for the generator to two: achieving planning permission and dealing with the electricity company.

Feed-in mechanisms are generally easier to implement than obligations. The European Commission report confirmed that obligations have higher administration costs.[Above n 31, page 5.]

Compatibility with a long-term price on greenhouse gas emissions

Feed-in tariffs are probably the least compatible with expected long-run measures if used on a widespread scale. There is a risk that, if the tariffs are stopped in favour of the price incentive of an alternative instrument, the level of payment to investors falls. Unlike similar mechanisms based on obligations (such as generation obligations), there is little scope for the development of a contractual hedge to reduce risks. This is the case for all renewable energy support schemes. Investment will be limited unless the measure is guaranteed to exist for a specified period of time.

Other issues

A feed-in tariff may or may not be consistent with the nodal pricing system and is an important topic for discussion. Ways to simplify a feed-in tariff include using historical nodal differences to scale the feed-in tariff at different locations or using a simple nodal system – for example, with a different price for South and North Island locations. Alternatively, a guaranteed price approach – essentially a contract for differences in some form – could be used.

Feed-in tariffs could be used for industrial use of renewable fuel as a payment per MWh of heat or electricity produced from renewable sources. However, this introduces problems that do not apply in its use in electricity generation, because the subsidy is occurring at the margin (for example, to units of energy used in setting transfer prices within a process, such as the price of heat as an input to pulp production). Germany is setting up a feed-in tariff for renewable heat.

A feed-in mechanism is often described as non-complementary to a liberalised electricity market. The electricity distributor is required to take all renewable electricity generated and to pay the generator the feed-in price. The feed-in electricity is bought and sold in parallel to the electricity market but does not directly participate in it.

5.5 Project based measures

General Description

Project-based schemes achieve emissions reductions by encouraging individual emission reduction actions. These abatement actions could involve emission reductions or sequestration activities. A definition of projects is that they:

• have identifiable boundaries

• include actions that can be observed, reported and verified

• have a plausible baseline against which the emission benefits of the abatement activity can be estimated

• provide an incentive – often in the form of credits – to achieve the abatement

• feature a way of excluding business as usual activities.

A project refers to a particular abatement or sequestration activity at an identifiable location that is individually managed and accounted for. Specific design elements vary from programme to programme, while meeting the properties identified above.

The purpose of developing a project-based framework is to motivate entrepreneurial efforts to reduce emissions by assigning a value to those emission reductions. In theory, awarding an incentive on a voluntarily-submitted case-by-case basis enables individual projects to achieve emissions reductions that are cost effective and real. They help to identify and initiate abatement activities and can be especially useful as a way to introduce emission price signals.

Many project-based frameworks have been used internationally. The most well known are the Joint Implementation (JI) and Clean Development Mechanism (CDM) flexibility elements of the Kyoto Protocol. Project-based activities are used to enable countries with emission obligations to receive emission units for investments in project abatement to reduce the costs of meeting their own emission responsibilities. The Netherlands Government’s ERUPT programme[ERUPT – Emission Reduction Unit Procurement Tender.] is an example of a JI project in which a country provides a monetary incentive in exchange for a future promise of emission units for 2008–2012 abatement from projects that occur in other countries that also have emission responsibilities under the Protocol (and hence an allocation of emission units).

A project not related to the Kyoto Protocol was the Australian Greenhouse Gas Abatement Programme (GGAP). The Australian government offered a large financial incentive for project-based abatement activities through a series of tender rounds. Another general type of project instrument could involve one sector of the economy (such as fossil-fuel generation) being given an obligation related to emissions that could be met by submitting project-based offset credits generation either by abatement from the same sector (such as. renewable energy) or another sector (such as provision of sink offsets). The financial incentive is provided by entities in the regulated sector purchasing the abatement credits to retire against their emission-related obligation.

A New Zealand example of a project-based framework is the Projects to Reduce Emissions (PRE) programme, which included two tender rounds in 2003 and 2004. The New Zealand government offered a forward promise of Kyoto Protocol-compliant emission units as an incentive for near-economic abatement activities based on the expected emissions reduction the projects would deliver during 2008–2012. At least one of the firms with project agreements forward sold its expected allocation of units to the Netherlands government under ERUPT.

Incentives for project-based approaches in the energy sector could be made in two ways: firstly, by providing financial payments either upfront or after delivery of abatement; and secondly, by awarding carbon credits, as in PRE. In many respects, the two models share the same advantages and disadvantages, although key differences between the two options include the degree of involvement by firms in the international carbon market and the way in which non-delivery risk is managed in project agreements.

The financial incentive could be provided either by the Crown or by entities within a regulated sector needing to purchase credits to retire against an obligation. One example of such a scheme is the TrustPower example in Section 5.1.3, in which abatement from new renewable electricity generation could create a matching liability allocated across fossil fuel generation. This liability would require the purchase and then retirement of abatement certificates purchased either from the new renewable generation or from international markets.

Evaluation

Cost effectiveness

The cost effectiveness of project-based frameworks can usefully be broken into two key points: (i) effectiveness – the extent to which project-based frameworks reduce emissions beyond business as usual levels, and (ii) the cost of the abatement. Project frameworks can also deliver significant co-benefits, such as ‘learning by doing’ for emerging technologies and helping them to become commercially mainstream as well as contributing to electricity security of supply.

The question of whether these projects create real emission reductions – in other words, emission reductions above business as usual – is referred to as ‘additionality’. Additionality analysis includes considering whether the activity would have happened anyway (economically and considering any barriers) and, if the activity goes ahead, what impact it has on emissions (both locally and system-wide).

Demonstrating additionality is essential to ensure the programme’s environmental effectiveness[Two options have been employed to help mitigate this concern: Additionality tests and performance standards or benchmarks. Additionality tests establish a methodology for ensuring that the reductions would not have occurred in the business-as-usual case. Performance standards ignore the question of why the emissions have been reduced and simply reward excellent performance – typically defined as performance beyond a well defined level that is stringent enough to ensure it is not a business as usual activity.] and to ensure that any funding is spent efficiently without supporting free riders and creating unwanted market distortions and windfall profits in industry. Additionality analysis is imprecise and will never be perfect. The 2005 Climate Change Policy Review raised some concerns about additionality and net costs to the Crown.

A continuing challenge is determining whether emission reductions are real and what their extent is. Greater testing rigour or higher performance standards would make it more likely that the reductions were above business as usual levels, but these tests would come with transaction costs and would have to be balanced against other desirable test characteristics (such as low cost, simplicity and administrative ease). Another approach would be to cover this risk by discounting the incentive and accepting that some non-additional proposals received incentives.

Project-based approaches are seen to be potentially cost efficient because they enable low-cost options to be developed. Once a price is established by government mandate or by participation in a tender or auction, project developers will submit projects generating reductions costing less than the set price, with lower cost offsets leading to greater profits for developers. Most project frameworks include eligibility assessment and highly contestable processes for applicants to access the incentive. The assessment processes are primarily to ensure value for the incentive provided, but usually also involves a careful risk assessment.

Offsetting this are the relatively high transaction costs than can be associated with projects. Protocols must be developed for project submission, approval and trading. Once the system is in place, an interested party must scope out potential projects, determine eligibility, submit a project for consideration and develop monitoring and verification plans as needed. Not surprisingly, this effort and expense reduces the benefit of the incentive and can eliminate some projects from consideration.

Experience with PRE indicates that transaction costs can be effectively managed, judging from the number of relatively small projects submitted (if transactions costs were too high, net benefits would be low, which would discourage participation). PRE also stimulated a large number of wind energy proposals which took this technology into the mainstream marketplace and are expected to significantly contribute to new supply.

Ease of implementation

Programmes in project-based framework designs range from the simple to the very complex. At the simple end of the spectrum, Australia’s GGAP programme achieves significant reductions through only 12 independently-approved projects. Other programs, such as the CDM, are much more administratively complex.[The CDM requires protocols to be approved for each project type, a detailed project design document to be evaluated, validation, registration and monitoring to be reviewed, etc (although simplified procedures are available for smaller projects).]

PRE was a relatively straightforward but effective example of a project-based framework, winning the Bearing Point Supreme Award for public sector innovation in 2004. It cost well under $500,000 in administration costs to run the second tender, which allocated an incentive of about $A100 million. Ongoing contract management of the portfolio of project agreements has required a little over a full-time equivalent staff member. The workload will vary through the lifetime of the agreements and will increase somewhat when abatement reporting over 2008–2012 results in the allocation of emission units. This experience will be invaluable should a successor programme be developed, whether for the energy sector alone or as a cross-sector measure.

A project-based framework uses a politically acceptable voluntary approach in which participants are compensated for reductions from the baseline rather than taxed based on their emissions. It achieves many of the same benefits as the carbon tax, but trades off administrative ease and environmental/tax funding source for political acceptability. Acceptance will also be influenced by who provides the incentive: government funding, an offset obligation on the sector, or even recycled revenues from an emission charge.

Impact on energy prices

With a project-based framework such as PRE, providing emission units to support marginally economic renewable energy projects could reduce electricity prices slightly. However, this represents a transfer of value from New Zealand’s portfolio of emission units to electricity users. A programme that was similar, but in which the incentive was provided by an obligation on fossil power generation, could be expected to increase electricity prices. The extent of the price rise would be related to the ambition of the programme, but conceptually it could vary from very low to similar to that of a price instrument such as emissions trading.

Compatibility with a long-term price on greenhouse gas emissions

Project-based frameworks are a very direct and feasible way for a government to reduce emissions and are perhaps most easily implemented in the energy sector. As a price-based positive incentive measure, they are a ‘carrot’ rather than a ‘stick’ transitional measure. The monitoring, reporting and verification experiences and international carbon market engagement (in the case of PRE) are also compatible with a longer-term price instrument, such as emissions trading. The design of any specific project-based framework would affect how well it fitted in with a broad long-term price measure, but the nature of project-based frameworks represent a good starting point.

5.6 Regulatory measures

General description

This section looks at direct regulatory options for discouraging fossil fuel electricity generation before 2012.

Readers should note that nearly all the measures described in this discussion paper could be described as regulatory measures. Legislation would be required to establish mechanisms supporting any emissions trading scheme, carbon charges or other systems. However, this section describes direct regulatory (or mandatory) options that could complement or serve as policy alternatives to those other measures.

In the absence of an economy-wide price on greenhouse gas emissions, a direct regulatory measure could specifically target new investment generation to ensure it was lower carbon than business as usual.

Any regulatory measures would be limited in direct application to new fossil fuel power plants. The measures would indirectly encourage new renewable energy by having an impact on the operational and infrastructural costs of fossil fuel plants and increasing electricity prices.

Examples of regulatory measures, standards or requirement on new fossil fuel (or just on new coal) that could be introduced include:

• a mandatory emissions-offset requirement for new generation (which could also be linked to emissions trading, as in section 4.1.3). The requirement could be for afforestation or geological emissions sequestration (carbon capture and storage, or CCS) to match some or all emissions from new fossil generation

• a requirement to be ready to use CCS when the technology became economically viable and practical; and/or to adopt emissions standards for new fossil fuel plant.

CCS involves the use of technology to collect and concentrate the CO₂ produced from industrial and energy-related sources, transport it to a suitable storage location, and then store it away from the atmosphere for a long time.

Compared to conventional generation, CCS could allow fossil fuels to be used with 80-90 percent lower emissions of greenhouse gases. However, CCS would raise energy costs. The technology is in its infancy and cost estimates are premature. In addition, there are a number of uncertainties associated with the development of an appropriate regulatory regime to deal with sequestration.

Once the regulatory measure is decided upon, the next issue would be the method of implementation. Two pieces of current legislation are explored: the Electricity Act 1992 and the Resource Management Act 1991 (RMA).

5.6.1 Using the Electricity Act 1992

The Electricity Act 1992 could be amended to enable the introduction of regulations controlling fossil fuel stationary energy generation.

Developing a carbon capture or offset requirement policy would require an overseeing/administering body. This would preferably be an existing body such as the Ministry of Economic Development, the Electricity Commission or the Ministry for the Environment.

This approach could be tied into any regulatory changes considered under the NZES and other energy sector work programmes.

5.6.2 Using the Resource Management Act 1991 (RMA)

The RMA provides various opportunities for central government to intervene in resource management policy and/or regulatory decision-making that is otherwise devolved almost entirely to local government.

These include issuing National Policy Statements (NPS) and National Environmental Standards (NES), and making specific responses to individual projects. These responses include:

• calling in applications for resource consent, notice of requirement or requests for private plan changes or regional plans

• making submissions on behalf of the Crown

• appointing a project co-ordinator for an application for resource consent to advise a local authority

• directing that a joint hearing be held if more than one authority is involved

• appointing a hearings commissioner in cases where a local authority has decided commissioners should hear an application.

There are other ways for the government to influence decision making that are not specifically provided for in the RMA or which are not specific to the government. These include issuing non-statutory guidance and making submissions on plans, consent applications and notices of requirements for designations.

The government can use an NPS or an NES in matters of national significance at stake and where it can be demonstrated that they are the most appropriate mechanisms having regard to their efficiency and effectiveness. Before adopting an NPS or an NES, the government must carry out an evaluation to demonstrate that the statutory cost benefit tests of section 32 of the RMA are met.

Under the current wording of the RMA, if the government wanted to use it to reduce or manage greenhouse gas emissions from large direct emitters, an NES would be the only effective national policy instrument. An NPS would not be effective alone because it does not contain rules and methods and has no direct effect on consents. An amendment to the RMA would be required.

If the RMA was amended to empower local controls on greenhouse gas emissions because of their effect on climate change, councils could use rules in plans and conditions on resource consents, applied locally on a case-by-case basis. The government would then also be able to use ministerial powers of intervention.

National Policy Statements

As stated above, the RMA would have to be amended to implement an NPS that enabled local controls on sources of greenhouse gas emissions because of climate change impacts. This section assumes such an amendment is made.[Note there is a Member’s Bill to remove the restriction on plans and consents dealing with impacts of discharges on climate change currently before the Local Government and Environment Select Committee.]

NPSs state objectives and policies for matters of national significance that are relevant to achieving the purpose of the RMA. NPSs can set out objectives and policies that local authorities must “give effect to” in their local and regional policies and plans, and which they must have regard to when making decisions on individual development projects.

As a result, there are two primary tests to be assessed by stakeholders. The first is whether encouraging or discouraging particular electricity generation types are, or could actually or potentially affect, a matter of national significance (see RMA Part 2 and s45(2)).

The second is whether an NPS could state policies in relation to electricity generation that address the issues associated with that activity and do so in a way that promotes the sustainable management of natural and physical resources as defined in section 5 of the RMA.

NPSs can influence both the local and regional policy environment, and the outcome of resource consent decisions on individual development proposals. NPSs do not, however, have the same direct or immediate effect as a regulation (or NES). Their effect will only be felt when a resource consent application (or designation) is required or when a local authority’s district or regional plans are changed to give effect to the NPS.

An NPS on electricity generation could cover some or all of the following issues:

• a range of detailed issues associated with each generation type (such as water allocation, discharges to air and water, landscape impacts and noise)

• issues relating to the development of renewable electricity generation

• generic issues with the way that electricity generation is managed under the RMA.

An NPS relating specifically to controlling greenhouse gas emissions from electricity generation could be combined with elements of an NPS on generic electricity generation issues.

It is unclear whether the marginal benefit to be derived from such a policy could be outweighed by the risks associated with unintended consequences and regulatory creep. Unintended consequences are the uncertainties about the impact the policy could have, and concerns that it could have an effect that has not been anticipated or desired. Concerns about regulatory creep are that the process of developing the NPS could lead to its scope being expanded beyond the minimal high level policies proposed.

National Environmental Standards

An NES is a regulation that prescribes technical standards, methods, or requirements in relation to the control of land, the coastal marine area, the beds of rivers and lakes, discharges to water or air, and noise. NESs are regulations that can over-ride local and regional rules. They can specify the performance standards required in relation to specific activities, or specify what category of resource consent should apply at local or regional levels.

NESs may:

• prescribe the outcome or level of performance expected from certain activities

• prohibit an activity

• permit an activity that does not have a significant adverse environmental effect, subject to any terms and conditions specified in the standard or in any plan

• allow an activity subject to a resource consent (including prescribing the consent category that applies, such as whether local authorities should regard the activity as controlled, restricted discretionary, discretionary or non-complying).

The first suite of NESs has recently been prepared for certain air quality matters, including standards in relation to dioxin and other toxics, ambient air quality, the design of wood burners and the control of landfill gas.

NESs do not need to be translated into a regional policy statement or plan before taking effect. However, as noted above, NESs can require local authorities to regulate activities in prescribed ways. In such cases NESs may be translated into rules in plans. Rules and resource consents cannot be more lenient than an NES. They can, however, be more restrictive than an NES if the NES specifically provides for that. Even where an NES exists, plans may continue to have a role specifying the requirements that apply to activities that are the subject of an NES.

NESs can also require the conditions of water, coastal and discharge permits to be reviewed. When conditions are reviewed, the NES prevails over whatever conditions applied prior to that review.

In theory, an NES could be applied to particular detailed issues such as noise from wind turbines, methodologies for landscape assessment and management of discharges from fossil fuel stations.

Evaluation

Environmental effectiveness and impact on energy prices

Without the specifics of a particular regulatory measure, it is very difficult to evaluate the impact on prices and environmental effectiveness of particular measures because they depend on the stringency of the measure and the specifics of what is being regulated for. However, in general, any regulatory measures are likely to result in increased cost to generators. This may raise electricity prices, but it is also likely to result in displacement of greenhouse gas emissions over time as a result of an increase in renewable generation.

It is unclear how environmentally effective an NPS (with RMA amendment) or an NES would be. A simplistic assessment might conclude that an NES, by prescribing outcomes and technical limits, would be better than an NPS, which gives local authorities some discretion over consent conditions. However, such a weakness is corrected by accompanying any NPS with NES and other guidance documents.

Cost effectiveness

Again, it is difficult to assess the cost effectiveness of introducing regulatory measures without precise details of the measure.

An NES is the least costly option because it does not require legislative amendment. However, it should be noted that, because all the RMA options devolve decision making to the local level, except when appealed to the High Court, costs are also transferred to the local level. NESs are subordinate legislation and there are costs of development and consultation.

One possible NES objective could be to ensure large emitters of CO₂ participated in a trading system. At this early stage of assessment, it is difficult to determine whether a NES is actually needed for this purpose, whether such a purpose goes beyond the bounds of what an NES can do, or whether participation would be guaranteed through the legislation that sets up the mechanism itself.

All the RMA options have a degree of ‘double jeopardy’ risk, where national measures might be implemented on top or in support of resource consent conditions.

Ease of implementation

CCS and offset regulatory measures are unlikely to be easy to implement. In particular, an amendment to the Electricity Act 1992 would require considering complex monitoring and enforcement requirements.

Both the NPS and NES options devolve decision making to local authorities. This introduces risks regarding consistency between regions, costs to all parties and litigious processes. It is debatable whether any RMA measure would provide clarity and certainty for all parties, as the RMA consenting process is open and risky, particularly for large projects such as a new fossil fuel power plant. However, there is less room for local variation in consenting issues through an NES than an NPS. This is because a NES has direct effect and the rules are standard across the country, while an NPS has to be implemented through plans and consents with inevitable room for local variation.

A NPS would be the least practical option because it would probably take a long time to develop and implement. It is highly likely that such a measure would need the development of national guidance, such as an NES.

An NES could be easier than an NPS to develop and to implement, created using existing powers, and written to have an impact only on new fossil fuel generation plants. It could also be written so that controls were consistent between regional authorities.

Compatibility with a long-term price on greenhouse gas emissions

The measures might not be incompatible with long-term measures, providing the regulatory requirements and time frames are clear and certain.

For measures with an element of trading, such as emitters fulfilling resource consent requirements through direct participation in an emissions trading system, the regulation could simply transfer to a broader long-term trading measure.

5.7 Voluntary measures

Voluntary measures typically refer to measures that are undertaken through agreement rather than mandated through direct legislation or financial incentives and penalties. However, voluntary measures could be the object of regulation where the participation in a commitment scheme is mandated by legislation. Several of the options discussed previously in this paper could be undertaken on a voluntary basis.

An example of a voluntary measure could be a written agreement between the government and the generator that would define the targets, the period and nature of the measure. The targets could be specified in terms of absolute greenhouse gas emissions in each year, emission intensity, or energy efficiency. Less direct measures are also possible, such as assurance that best available technologies are being used or that a marginal shadow price for CO₂ emissions is being incorporated into decision-making.

A wide range of processes and tools could be used for establishing a target. For instance, target setting could be by negotiation between the Crown and the participant firm or sector, through an energy audit and an agreement to implement cost-effective measures, or through a requirement to meet some standard of best practice for the participant’s plant.

A voluntary agreements scheme could feature:

• agreed targets and public reporting of performance against targets

• mandatory consequences for non-performance against targets, with limited stringency

• limited pilot emissions trading and other flexibility mechanisms, facilitated by the government

• assurances that participation in the scheme would not disadvantage participants for the later price-based measure (in other words, that any grandparenting approach for emissions trading would be based on performance prior to entry into the agreement)

• mandatory monitoring, reporting and verification of emissions for generators participating in the scheme and for those who are not participating.

Evaluation

Environmental effectiveness

It is difficult to ensure environmental effectiveness with voluntary measures. Voluntary initiatives can significantly reduce greenhouse gas emissions in some situations, but empirical evidence of voluntary approaches often shows they are most effective when implemented in association with a regulatory consequence if no progress is achieved. Such measures, although they are likely to produce results, then start to closely resemble several of the instruments already discussed in this paper.

Cost effectiveness

Negotiating individual performance agreements that assessed specific generation sites and performances would be a difficult, costly and drawn-out process for all parties. An early conclusion would be that voluntary agreements would not represent a cost-effective approach to achieve the objectives of this work programme.

Ease of implementation

See above analysis of cost effectiveness.

Compatibility with a long- term price on greenhouse gas emissions

If entry into a programme and acceptance of a commitment are both voluntary, generators would need to be motivated to participate. A possible incentive could be a connection to any longer-term price measure. For example, subsequent allocation decisions could recognise voluntary targets or achievements. Generators that participate and meet their commitments could be assured their allocations would be based on a different formula or based in some way on their monitored achievements.

From a different point of view, this may be regarded as credit for early action – a framework for participants to record achievements to ensure that subsequent allocations do not penalise actions taken before the allocation decisions are made.