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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

A wide range of policy options is available to encourage low emissions energy supply and a transition to greenhouse gas pricing [Some of the information in this document was sourced from some preliminary analysis by Covec Ltd commissioned by the Ministry of Economic Development and the Energy Efficiency and Conservation Authority. Covec’s report is titled Policy Options to Encourage Renewable Supply.].

There are many ways to categories these options, such as whether they:

• are mandatory or voluntary

• rely on market (price-based) signals to steer investment decisions or regulations to directly encourage or discourage certain types of activity or technology (such as renewables).

The groups or categories of policy measures considered in this discussion paper include:

1. emissions trading
2. a CO₂ charge (narrow based)
3. renewable obligations
4. incentives/subsidies
5. project based measures
6. direct regulatory options
7. voluntary measures.

Each of these groups has a potentially wide number of options, depending on design. One key design choice is whether a measure is to apply to electricity only, or to electricity and industrial heat and power. Another is whether a measure should apply to all existing capacity or production, or focus only on new capacity or investment. These choices will determine the effectiveness of the measures, as well as their impact on energy prices or other costs.

This paper attempts to limit the discussion to two or three options for each category. Each option could be implemented in the near term. The resulting list of options is by no means exhaustive.

5.1 Emissions trading

An emissions trading scheme requires a group of emitters to hold tradable units or allowances to match some or all of their greenhouse gas emissions over a defined period. Emitters can either reduce their own emissions or trade allowances to meet their obligations. While there are a number of types of emissions trading schemes, two principal options analysed in this paper are the cap and trade and baseline and credit models. The difference between the two is that the cap and trade model uses an absolute framework, in that allowances must be surrendered to the authorities for every tonne (or other unit of quantity) of emissions produced, while the baseline and credit trading model uses a relative framework, where only deviations from an emissions baseline must be accounted for.

Emissions trading schemes are particularly suited to sectors in which emissions can be estimated and reported accurately at low cost, which have a reasonable number of emitters, and in which the transaction costs of covering those emitters are not unreasonably high. The stationary energy sector and industrial processes sector generally fulfil these requirements and have been the main target for these kinds of measures internationally.

A third option is to allow for trading of cross-sectoral offset credits, either as a stand-alone model or along with either cap and trade, or baseline and credit models. Alternatively, any emissions above a specified level could be required to be compensated for with offset credits, which would in turn be tradable.

5.1.1 Cap and trade

The main feature of a cap and trade scheme is that a fixed ceiling or cap is set for a certain type of emissions (international examples are CO₂ and NO_x) over a set period of time in combination with tradable emission allowances. A cap and trade scheme is in effect a regulation with a market component. The allowances are initially allocated in some way (e.g., based on historical emissions, auctioned or purchased at a fixed price), typically among existing sources. Each source covered by the programme must hold allowances to cover its emissions, and is free to buy and sell from other sources.

Essential elements of a cap and trade scheme are:

• emissions are capped at some level in each period

• permits to emit greenhouse gases are issued for each period

• there is a penalty for non compliance.

Key design issues include:

• point of coverage

• threshold for entry

• use of offsets

• methods of allocation of allowances.

The main allocation methods available are gratis or free allocation, auction, or setting a requirement to purchase project or offset-based credits. Gratis allocation methods include “grandparenting” of units to existing emitters on the basis of historic emissions, and providing units to emitters on the basis of projected emissions. Allocations need to be consistent with the concept of a cap on the quantity of emissions, so that the number of units allocated does not vary with changes in production levels. Unit allocations would generally be made before or at the start of a trading period, as the quantity of units to be allocated would be determined in advance.

For a more detailed evaluation of the implications of these design options, refer to the discussion paper on long term policy measures, Measures to Reduce Greenhouse Gas Emissions in New Zealand Post-2012.

Linkages with international markets

The introduction of a domestic emissions trading scheme raises the possibility of linking with trading schemes in other countries. The main argument for linking is the base economic argument for introducing an emissions trading scheme. The greater the scope of the schemes, the greater the range of mitigation options available to market participants – enabling the aggregate emissions cap of the linked schemes to be met at a lower cost.

Linking with other schemes could enable a New Zealand emitter to buy and sell units outside the domestic market. One option would be to link a domestic trading scheme to the Kyoto emissions trading market by trading assigned amount units, or other Kyoto ‘currencies’ such as emission reduction units (ERUs)[Created under Article 6 of Kyoto Protocol – Joint Implementation.] or certified emission reductions (CERs).[Created under the Kyoto Protocol’s Clean Development Mechanism (Article 12).] A second option would be to link a domestic trading scheme to another country’s emissions trading scheme, such as the European Union’s Emissions Trading Scheme (the EU ETS).

One benefit of linking is that it sets an upper limit or safety valve on the price of allowances, so the price on the domestic market cannot exceed the international price. Because linking requires some conformity between different schemes, the design of a domestic scheme is critical if linking is to be possible.

Evaluation

Environmental effectiveness

A key argument in favour of cap and trade schemes is that they provide a certain environmental outcome. A cap is set on emissions from the sector, and the stringency of the cap determines the reduction in emissions.

Cost effectiveness

A cap and trade scheme is a relatively low cost way of reducing emissions in some sectors, potentially including the stationary energy sector. This is because cap and trade regimes provide emitters with flexibility to identify and use least cost abatement opportunities across the sector.

Methods of allocation would impact on the cost effectiveness of the scheme.

A cap and trade regime with auction covering the stationary energy sector would be comparable in its cost effectiveness to a CO₂ charge. The major difference between the two systems is that a cap and trade scheme gives greater certainty as to the amount of emissions from the sector, whereas a CO₂ charge gives greater certainty about the cost.

A cap and trade scheme with grandparenting is a less cost-effective measure than cap and trade with auctioning.

Impact on energy prices

The impact a cap and trade scheme has on energy prices will depend on the stringency of the cap, the methods of allocation, the stringency of non-compliance methods and the potential for cross-sectoral and wider market linkages.

A cap and trade scheme with auctioning could be expected to have a similar effect on energy prices as a CO₂ charge if the cap was set at a level that reduced emissions by about the same level. The price of electricity in any time period is set by the marginal cost of production (the costs of the last unit of production). Fossil fuel plants invariably set price because they have higher variable costs of generation than fossil fuel alternatives. Plants will need to surrender allowances for every unit of emissions, and this results in a cost for every unit of electric output from fossil fuel plants. Even if a firm is gifted allowances, the need to surrender an allowance means that allowances cannot be sold; this is a cost.

The effect cap and trade schemes with grandparenting or other methods of gratis allocation have on energy prices will depend on the level of grandparenting applied. The price effect can be reduced by increasing the amount of grandparented units, leading to a similar reduction in price impacts as achieved by reducing the stringency of the baseline applied under baseline and credit trading. However, in some market conditions, a cap and trade system with grandparenting may create additional price effects compared with baseline and credit trading if producers pass the opportunity cost of allowances on to consumers.

Ease of implementation

There can be substantial cost and time required to establish institutions to monitor, report and verify emissions and provide for allocation and trading of units under a cap and trade system. Industry participants would also be faced with costs and time developing expertise in emissions trading. To the extent that any gratis allocation of units is negotiated or tailored to individual companies or sectors, substantial time or resources may also be spent in determining allocations.

Compatibility with a long term price on greenhouse gas emissions

A cap and trade system is very compatible with a move to longer-term full-price measure, particularly if there are good linkages to an international market to help make the transition to an international price. A cap and trade system also offers a number of options to make a gradual transition to full pricing through initial gratis allocation of all or a portion of emissions, or through options to include price caps or offset trading. If an emissions trading scheme was to be adopted across the economy as a long-term measure, early adoption of a cap and trade system in the stationary energy sector would be a good opportunity to develop experience in trading and managing liabilities.

Other issues

Under a cap and trade scheme with grandparenting, an emitter is allocated a larger amount of units than under a similarly stringent baseline and credit scheme, and receives the units in advance. Those units are an asset available for trading and have an opportunity cost: using the units to match emissions from production means that those units are not available for sale. It is in the emitter’s interests to pass on some or all of this cost to consumers if market conditions enable them to do so (if all producers in the market faced the same opportunity cost and there was no risk of being undercut by foreign producers).

Some firms could gain by simply ceasing production and selling their allocations. This might be considered a good outcome, especially if the firm uses an excessively greenhouse gas-intensive technology. If the firm ceases production, the credits can then be sold to other firms which can use them more productively. However, this could be seen as giving firms an unfair ‘windfall’ profit and providing them with a perverse incentive to shut down. Rules could be introduced to claw back the credits if a firm chose to shut down, but these rules could get complicated as firms could scale back their operations without shutting down completely.

5.1.2 Baseline and credit

In baseline and credit schemes, individual emitters are assigned an emissions baseline which represents a schedule of allowable emissions over time. These can be defined on an absolute or an intensity basis.

Emitters are exempt from carrying a liability for their emissions up to a baseline level, which has to be less than actual emissions to have a substantial effect. If the scheme is based on absolute emissions, it is no different from a cap and trade scheme with grandparented allowances. The only allowances likely to be traded are associated with deviations from the initial allocation.

Baseline and credit schemes start to differ from cap and trade schemes when they are designed on the basis of emissions intensity: sources must buy additional allowances when their emissions rate per unit of activity (energy input or output of energy or product) exceeds the baseline level. The system allows emitters to increase their total emissions without being required to buy more allowances, as long as the emissions are the result of increased activity rather than a change in the emissions intensity of the production.

For electricity generation, the baseline might be established on a straightforward basis as an allowed rate of emissions per MWh of output. For industrial energy, establishing the baseline would be more complicated. It might be established based on historical emissions use per unit of the firm’s output (such as tonnes of commodity produced) or per dollar of output. However, any industrial baseline would need to be carefully designed to insure it was fair and did not produce perverse incentives, such as an incentive to produce lower-valued products. One obvious alternative would be to apply the baseline and credit scheme to electricity only.

For the purposes of this discussion paper, baseline and credit schemes are taken to operate on an intensity basis, with an emitter’s baseline expressed in terms of tonnes of emissions per unit of production.

A major distinction between baseline and credit schemes and cap and trade schemes is the timing of provision of allowances to participants. While the intensity baseline is determined in advance for baseline and credit schemes, the actual amount of production and the emissions intensity of that production is not known until the end of the year (or other period used). Consequently, emitters do not know the extent of their liabilities or benefits until the end of the period, when emission allowances are allocated. With cap and trade schemes, the amount of the cap is known in advance irrespective of production levels, so allowances can be allocated with certainty at the start of the period.

Evaluation

Environmental effectiveness

As with the other price-based measures discussed, the environmental effectiveness of a baseline and credit scheme depends on the stringency of the measure or on how much of an improvement the baseline is on business as usual. As defined here, the baseline is based on emissions intensity, which gives a less certain environmental outcome than a cap and trade system. Under a baseline and credit system, if overall production increases the total amount of emissions from the scheme can increase without emitters being required to meet any further obligation, as long as their emissions per unit remain below the baseline level.

Cost effectiveness

Baseline and credit emissions trading could be a relatively low cost way of reducing emissions from the stationary energy sector. [However, as baseline and credit trading operates at the margin, it may offer less of an incentive to use least-cost emission abatement opportunities across the sector.]

Impact on energy prices

Baseline and credit schemes imply a level of protection from an emissions obligation (up to the baseline). The impact on energy prices may be reduced by setting a less stringent baseline. A cap and trade scheme can have a similar effect by grandparenting emission units.

Ease of implementation

As with cap and trade emissions schemes, it could be expensive and time-consuming to establish institutions to monitor, report on and verify emissions, and to enable units to be allocated and traded. Industry participants would also be faced with costs and time establishing expertise in emissions trading. The financial risk to participants might be less with a baseline and credit scheme, as trading is at the margin and involves a smaller asset allocation.

A baseline gives each participant an emissions intensity target and a time frame in which the target must be met for each participant and sets out a time path along which emission reductions are to be achieved. To the extent that a company-specific baseline attempts to incorporate a detailed assessment of factors such as future industry performance and abatement opportunities available, establishing a baseline could be a cost-intensive process. However, this might not necessarily be any more complicated than allocation methods under cap and trade regimes (especially in the case of grandparenting).

There may be additional costs and complexities in a baseline and credit system associated with determining under and over-performance against the baseline, and to allocate units at the end of each time period, compared to an advance allocation of units under a cap and trade system.

However, a baseline and credit system may reduce some of the risks of windfall gains that are associated with a cap and trade system. Units under baseline and credit systems are based on actual production, so reductions in production should not create windfall gains.

Compatibility with a long term price on greenhouse gas emissions

A baseline and credit scheme gives a level of protection from the cost of emissions up to a baseline. However, it could be relatively easy to move towards full emissions pricing in the future by adjusting the baseline. The scheme could also help develop the expertise needed to set up a cap and trade scheme, but at relatively lower risk as there would be fewer assets and obligations involved.

Production increases in baseline and credit trading are unconstrained, which means the system has limits in enabling the sector to make the transition to measures that create a defined limit on emissions.

5.1.3 Trading of cross-sectoral offsets

The word ‘offsets’ or ‘offset credits’ describes a reduction or removal of greenhouse gas emissions that counterbalances emissions elsewhere in the economy. In the context of this paper, offsets can be activities that are funded by the electricity and industrial heat and power sectors to reduce or sequester emissions in other sectors, such as agriculture or forestry. The concept of offsets – or, more specifically, offset credits – and project-based activities described in section 4.5 often overlap because activities that generate offsets credits tend to be in the form of projects: an activity at an identifiable location that is individually managed and accounted for. This section looks at offset credits that are used in conjunction with emissions trading. One way of trading in offset credits is to design a trading scheme – such as cap and trade, or baseline and credit – and allow for offset credits to enter the market. This is a common feature of emissions trading schemes, and effectively means certain types of offset credits have the same value as an emission unit.

In general, allowing for offset credits as part of domestic trading schemes will improve both cost effectiveness and (more contentiously) environmental effectiveness and lessen the impact on energy prices compared with a ‘closed’ domestic scheme. This is because allowing for offset credits broadens the scope of a domestic trading scheme. This will help to reduce compliance costs for the sector facing the cap and, in theory, leaves net emissions unaltered. Trading in offset credits can also help to encourage emission reductions from sectors that are not as well suited to a cap and trade regime, such as the agricultural sector.

The main concern about offsets is whether the activities for which the credit is given genuinely reduce emissions (or, in the case of sequestration projects, remove emissions). This issue is discussed further in section 4.5. There is also concern that offset credits may weaken the capped sector’s incentive to reduce emissions.

A second option would be to create a market that trades solely in offsets by requiring any additional greenhouse gas emissions from electricity and industrial heat and power sources to be compensated for by offset credits, which could be traded. This option is evaluated further below.

Evaluation

A system that requires offsets only on additional greenhouse gas emissions would operate at the margin and have less impact on price than an approach that put a cost on all emissions (such as a full CO₂ charge at the international price of emissions, or a cap and trade scheme without grandparenting). There would be fewer incentives to identify the least cost emission abatement measures than with options that applied a full price to all emissions.

It would also be necessary to determine what constituted new emissions, and who would take responsibility for them. One approach would be to allocate all emissions above 2006 levels between fossil fuel electricity and generators based on their percentage of total emissions.

5.2 A CO₂ charge (narrow based)

Description

Greenhouse gas emissions from energy production or industrial activity are a classic example of an economic externality. In other words, there is a negative consequence of this activity that the emitter does not take responsibility for. In theory, an ideal solution is to charge emitters the full cost of the pollution they produce.

In practice, it is extremely difficult to estimate the full costs of pollution, but a CO₂ charge aims to move towards society’s preferred level of carbon dioxide by raising the price of the activity causing these emissions. A charge could change behaviour in both production and consumption patterns, depending on how much of the charge is passed on to consumers, and how much of it is absorbed by the emitter.

A CO₂ charge does not differentiate between types of energy supply, such as renewable energy sources, but gives equal incentives or disincentives to all energy supplies, based on their carbon content. For this reason it can be described as a ‘technology neutral’ intervention.

Ideally, a CO₂ charge would apply to emissions wherever they occurred in the economy. The feasibility and implications of using a broad-based greenhouse gas charge are considered in the discussion paper Measures to Reduce Greenhouse Gas Emissions in New Zealand Post-2012. Conversely, the focus of this discussion paper is on options for applying a charge on CO₂ only in the energy sector.

As is the case with all the options discussed in this paper, a number of design choices would have to be made to introduce a CO₂ charge. The most important choices would be:

• the rate of the charge

• how the revenue from the CO₂ charge would be used – a decision which would have a major impact on public attitudes to the charge [See the discussion paper Measures to Reduce Greenhouse Gas Emissions in New Zealand Post-2012 for more discussion on revenue recycling options.]

• the definition of large emitters[See the discussion paper Measures to Reduce Greenhouse Gas Emissions in New Zealand Post-2012 for more discussion on thresholds for entry.]

• the point of obligation. Decisions would have to be made on who is the liable party for a charge. The point of obligation can either be placed upstream on those who introduce greenhouse gases to the economy (such as coal mines, oil importers, gas extractors) or downstream on emitters, who combust fuel.

5.2.1 A CO₂ emissions charge on electricity and industrial heat

The introduction of a CO₂ emissions charge would change the cost of generation of electricity and heat from fossil fuel sources relative to renewables, as demonstrated in Tables 1 and 2.

Tables 1 and 2 show the impacts of a NZ$15/tonne, NZ$25/tonne and NZ$50/tonne price of carbon dioxide emissions.

Table 1: Impact of Carbon Dioxide (CO₂) Price on Electricity Costs [Electricity cost impacts were computed based on average 2004 emissions per kWh for each fuel. Emissions are given in New Zealand Energy Greenhouse Gas Emissions 1990–2004, Ministry of Economic Development, Tables 2.2.3 (for coal and gas) and E.14 (for geothermal). Electricity output is given in Ministry of Economic Development, New Zealand Energy Data File, January 2006, Table G.3.]

Table 2: Impact of Carbon Dioxide Price (CO₂) on Industrial Fuel Costs [ Industrial fuel cost impacts were computed based on kt CO₂/PJ emission factors given in New Zealand’s Energy Outlook to 2030, Ministry of Economic Development, Section 4.3 and net energy contents shown in New Zealand Energy Data File, Ministry of Economic Development, January 2006, Table M.6 (gas) and M.4 (sub-bituminous coal).]

Figure 2 illustrates the effect of a CO₂ charge on the demand for renewables. This figure pictures the current use of renewables as being the outcome of the costs of supply and demand for renewables.

The initial supply curve for renewables is (S0). Demand for renewables (D0) is pictured as a horizontal line based on the price of alternative fuel supplies. An amount is supplied under market conditions equal to Q0. The impacts of a CO₂ charge are illustrated as a change in the demand curve; the new curve is pictured as D1.

This change occurs because the cost of fossil fuel alternatives is raised. As a result, the wholesale electricity price rises and renewables further up the supply cost curve are supplied to the market, an increase from Q0 to Q1. This would be caused by building of new plant. Note that this is not an increase in total electricity supplied, which would decrease as a result of the CO₂ charge because of the increased wholesale price. Instead, it is an increase in the quantity of renewable energy supplied at the expense of supplies of fossil fuel fuels.

Evaluation

Environmental effectiveness

As for the other price based measures discussed thus far, the effectiveness of a CO₂ charge would depend on the stringency of the measure: in this case, the level of the charge and the opportunities for fuel switching. Generally, CO₂ charges will be effective in terms of reducing emissions beyond business as usual. However, the environmental outcome of a CO₂ charge is less certain than the outcome of, for example, a cap and trade scheme, which sets an absolute emissions target.

Cost effectiveness

CO₂ charges (and other price-based measures) are generally regarded as cost effective because they set a price in the market and allow operators to use their own internal information to decide whether it is more cost efficient to reduce their emissions or pay the charge.

Impact on energy prices

Energy prices will rise under a CO₂ charge, reflecting the price of CO₂ and the carbon intensity of the marginal generation fuels. The result is that the wholesale price of electricity reflects the marginal costs of supply, including the costs of CO₂. This is considered an efficient outcome.

In industrial heat and power use, the impacts include changes in supply costs and, in turn, the costs of production. In some cases, this leads to changes in output prices, depending on whether prices are set in the domestic market or internationally.

Additional entry of renewables may eventually reduce electricity prices because most renewables have zero or very low variable costs. This effectively pushes the short run supply cost curve outwards. However, these effects are taken into account by new entrants and while this limits the extent of new entry, the equilibrium will settle at a higher price because of these measures and lead to some new entry.

For industrial uses of fossil fuel fuels, the effects are similar. The equivalent impact on the wholesale price of electricity occurs in the form of a change to the marginal cost of supply of heat within a plant. Additional supplies of renewable energy occur where the changed cost of supply from fossil fuel fuels increases above the costs of supply from renewables. The main difference is that in heat plants there is some scope to use additional quantities of renewable fuels within existing plants, such as wood waste in existing solid fuel-fired plants.[This is limited to boilers that have a grate, e.g. it cannot be used in pulverised fuel plants.] In theory, these fuels could also be used in electricity plants, but it is more likely to occur closer to the fuel sources.

Ease of implementation

A CO₂ charge is conceptually simple and requires only the estimate of emissions – this is already undertaken for inventory purposes and is straightforward for fossil fuel combustion. New legislation would be required to introduce a CO₂ charge.

Compatibility with a long term price on greenhouse gas emissions

A narrow-based CO₂ charge would be broadly compatible with any future policy mix which included broad-based price measures such as an economy-wide CO₂ charge or a cap and trade regime. A narrow-based CO₂ charge would in effect introduce a price on emissions that would ensure those responsible for emissions began to take the costs into account. The introduction of a price on emitting, even at a low initial level, would be expected to lead to greater focus on future price trends, which would reduce the risk of stranded assets.

Other issues

A CO₂ charge would be passed on to firms in the form of higher electricity prices. A key issue to consider is how to manage this impact, especially for those firms which might have their competitiveness put at risk.

5.3 Renewable obligations

Instead of targeting greenhouse gas emissions directly, policy measures can target renewable energy as a specific emission reduction solution. Industry participants can be required to demonstrate that a targeted quantity of renewable capacity is installed (capacity obligations) or output of electricity or heat is generated or sold (generation obligations).

Obligated parties must provide the renewable energy themselves or ensure it is provided by someone else. The obligation might be allocated to suppliers or retailers on the basis of their activity, such as the quantity of generation or the sales of electricity, or on the basis of capacity. It can also be allocated to generators. In addition, the definition of renewable energy has to be agreed so that the eligibility of different technologies is clear.

Compliance can be guaranteed by issuing green certificates when energy is generated from renewable sources or capacity is available for which the obligated party pays. The necessary components of such a system include:

• an obligation or target

• an obligated party

• a defined means of compliance and demonstrating compliance

• penalty regimes.

Most generation obligations are found in Europe, while most capacity obligations are found in North America. [Renewable Energy Global Status Report 2006, REN21-Renewable Energy Policy network for the 21st Century, available on http://www.ren21.net.] So far, obligations have been introduced when renewable energy is more expensive than alternative, conventional electricity. In these situations, a monetary value has been placed on the green certificate, which raises the price paid for the renewable energy. For example, in the UK a buy-out value of 3p/kWh (around 9cNZ$/kWh) was implemented. It is possible, however, that no value is placed on the green certificate so that it remains mainly as a means to place an obligation and check compliance, although it is possible that a positive value may develop through trading.

In New Zealand, there would have to be careful consideration of how geothermal generation could fit into this scheme. Geothermal is generally considered renewable, but it does produce greenhouse gas emissions, the levels of which vary widely from field to field.[CO₂ is naturally released from geothermal fields to some extent, so the net impact may be less.] On average, these emissions per MWh are considerably lower than fossil-fuelled generators. However, greenhouse gas emissions from some geothermal fields are almost as high as those produced by fossil-fuelled generators.

5.3.1 Generation obligations

A generation obligation is specified in units of output. For example, a company might be required to ensure a percentage of its total supply or a specified quantity (in Mwh) is generated from renewables.

There are a number of renewable generation obligations and their details vary. For example, it is possible to incorporate minimum payments and/or minimum contract lengths, which reduces risks for investors.

In New Zealand, as with any country implementing an obligation, there may be initial market uncertainty over the price of green certificates because it would be a new market and it may take some time for price expectations to be defined. For investors in renewables, the risk is that certificate prices would be volatile. If there was any excess renewables capacity, it would fall outside the obligation and would not attract a ROC value. If there was under-supply, prices would be likely to rise to the costs of the non-compliance penalty (or the buy-out, if the UK approach was adopted). In addition, New Zealand may face market power issues that may not apply in larger countries.

5.3.2 Capacity Obligations

Capacity obligations would require total renewable capacity or new capacity within a given time period to equal a targeted amount. For example, each generator could have an obligation to hold renewable capacity equal to a specified percentage of its total, or a specified total in MW.

An obligation can apply to new or to all renewable capacity. For example, the obligation might be for 100MW per annum of new capacity or for 6500MW of total renewable capacity in some future year. If it is the latter, the obligation must make clear what new renewable energy is required, as Texas did but Maine did not. As a result, there has been minimal additional renewable capacity in Maine.[Langniss and Wiser, The Renewables Portfolio Standard in Texas: an early assessment, Energy Policy 31 (2003) 527-535; Bird et al, Policies and market factors driving wind power development in the US, Energy Policy 33 (2005) 1397–1407.]

An alternative specification is for the average percentage of all new generation, as a portfolio, to meet a target. This is easiest to achieve when there is considerable growth in demand, or if the target is 100 percent (all new capacity must be renewable). It becomes difficult if growth rates are low and plants are lumpy. Fossil fuel plants in particular are large, and if a company was to build a new fossil fuel plant it might be difficult to achieve targets. For example, a target of 75 percent of all new capacity would require a large additional investment in renewable generation to accompany any new fossil fuel plant.

As well as options for the nature of the obligation, there are options for the allocation. Aggregate obligations can be allocated to individual plants or firms in proportion to their percentage of capacity, or of generation or output:

• Their percentage of capacity can be either all capacity, or all fossil fuel capacity.

• Their percentage of generation or output can be all output (or sales), all fossil fuel output, or all CO₂ emissions.

For generation or output-based allocation, the obligation might be defined in the previous year (in which case each firm or plant is allocated the target divided by last year’s activity), or it might be based on anticipated activity levels in the current year (the target is divided by expected activity this year to define a rate of allocation for each actual unit of generation). This may lead to some over or under-allocation of responsibility. Using last year’s activity is likely to be a better option.

As with generation obligations, details of the different measures can differ. For example, it is possible to impose a minimum payment. [Langniss and Wiser, The Renewables Portfolio Standard in Texas: an early assessment, Energy Policy 31 (2003) 527-535; Bird et al, Policies and market factors driving wind power development in the US, Energy Policy 33 (2005) 1397–1407.]

Trading

While obligations can operate as regulatory measures in which obligated parties must either provide the renewables themselves or contract for it, generally these measures operate via a market mechanism in which the obligation (green) certificates [Green certificates (GCs) are known by a plethora of other names, e.g. Renewable Obligation Certificates (ROCs in the UK), Renewable Energy Certificates (RECs e.g. in Texas), Tradable Renewable Certificates (TRCs), Green Tags, Green Labels, Green Tickets, Tradable Renewable Energy Credits (TRECs) and Renewable Resource Credits (RRCs).] (such as ROCs or Texan RECs) are able to trade separately from the electricity. Under a market approach, for each unit of renewable electricity created, one unit of electricity enters the electricity market, and one green certificate enters the renewable obligation market. Some of the attributes of a green certificate market can be achieved through efficient contract markets, but tradable green certificates can in theory allow anyone entry to generate and, through trading volume (a liquid market) and price transparency, help provide the signals for least-cost achievement of obligations.

In Europe, the majority of obligations were implemented around 2000. At that time, it was envisaged that a green certificate market would develop and eventually link in some way with greenhouse gas emission trading schemes, which was considered a key benefits of the obligation. However, tradable green certificate markets have not developed either internally in the countries where the measure is in existence (such as the UK) or across borders (such as between Germany to France). The Netherlands was the only European country which initially allowed trans-border trade but closed the option when it became clear it was paying for existing renewable energy from other countries. In addition, there has been no increasing linkage of green certificates with greenhouse gas trading.[W. G. Arkel et al, The Dutch Energy Policies from a European Perspective; Major developments in 2003, ECN Report No: ECN-P-04-001, available on www.ecn.nl.]

Evaluation

Environmental effectiveness

Renewable obligations focus on promoting renewable energy. This means they are promoting a different and more limited outcome than some of the other measures reviewed in this paper, which can make comparison difficult. Literature reviewing the effectiveness of renewable obligations tends to focus on the programmes’ success in encouraging new entry of renewables and diversity of supply.

An alternative way of addressing this criterion is to ask whether one particular mechanism will deliver greater investment and installation of renewables than business as usual. In general, a well-designed renewable obligations scheme can be expected to deliver more renewables than under business as usual, although probably less than the feed-in measure discussed later.

Cost effectiveness

In general, renewable obligations are unlikely to be as cost effective in reducing greenhouse gas emissions as price-based measures such as emissions trading and CO₂ charges. However, renewable obligations can provide incentives for new entry at least cost, reward investment in all types of renewable capacity, and reward all investors, depending on the detail of the design.

Obligation mechanisms can be un-banded, which means they do not specify any particular type of generation to be bought or capacity to be installed. The UK Renewable Obligation and the Texas RPS are both un-banded. In these cases, the generation or capacity supported through the obligation tends to be the cheapest available, and does not provide support for more expensive, less mature technologies. It is possible to ‘band’ obligations or design them to support particular technologies, although this can lead to difficulties in trading.

To meet a given level of new capacity, capacity certificate payments may be lower than generation certificate payments because of output uncertainties. For industrial use of renewables, capacity cannot necessarily be restricted to a specific fuel type, so a generation option may be preferable.

There is potential for market power where a single or small number of firms dominate the supply of certificates or where an area has only a single supplier which is purchasing generation and could exert influence on the price paid or the length of the contract.

The price of certificates will depend largely on the expected duration of the policy and whether revenue from certificates can be expected over the life of the plant. If not, certificate prices will be higher.

Impact on energy prices

The impact on electricity prices will depend on how much generation or capacity the obligation is for and the value of the green certificate. As more generation is supported by an obligation mechanism, for example ten percent of the total market, then the size of the competitive market is reduced to 90 percent and the more expensive conventional electricity is pushed out so that the price of non-obligation electricity falls. If the combined cost of the obligation electricity and green certificates is equal or lower than the cost of the ten percent of conventional electricity, the price will stay the same or fall. If the combined value of renewable electricity and green certificate is higher than the average cost of electricity, then the average cost of electricity can be expected to rise.

In a country where renewable energy is no more expensive than conventional electricity, the green certificate value can be set to 0p/kWh. However, in general green certificates do have a value and the mechanism has led to an increase in energy prices. The extent to which this feeds through to energy bills will differ in each country or state using green certificates.

The impact on electricity prices will depend on who has the obligation. More specifically, prices will be affected if the level of obligation increases with each additional output of electricity. The impact is greatest if the obligation is concentrated on generators that are setting electricity price, such as fossil fuel generators. Basing the effect on last year’s activity should not affect this result significantly, as the impact at the margin is simply discounted by one year.

An alternative way to express the obligation is on capacity – by obliging a firm to hold certificates in proportion to its total generating capacity. There is no change in the level of obligation with level of output, and no impact on the cost of electricity if the obligation provides no extra payment. However, there will be an extra cost if the obligation does lead to extra payment.

A benefit of an obligation for generation and capacity is that a maximum annual cost is roughly known, although it differs for different mechanisms. If a price per kWh and an amount of capacity is known, the maximum annual cost is known. If either capacity or price is known there is less certainty. The UK legislation allows the supply companies to incorporate their extra costs into their supply tariffs so that, ultimately, the costs fall on consumers and are paid via their electricity bills.

Ease of implementation

Establishing a renewable generation or capacity obligation requires the definition of a new legal commodity – a renewable generation certificate. This would require new legislation. The necessary components of the system would include:

• an obligation or target

• an obligated party

• a defined means of compliance and demonstrating compliance

• penalty regimes for failure to hold enough certificates.

Establishing an obligation is more complicated than incentive mechanisms because of the need to check compliance. Trading would also increase the administrative burden.

A generation or capacity obligation, which has no minimum payment, obliges a supplier or retailer to buy the electricity and is integrated into the electricity market, just like any other generation bought by the supplier. This would make it easier to implement in the electricity market.

Compatibility with a long-term price on greenhouse gas emissions

Obligations require targets to be met. For example, most European countries have a target of an additional ten percent of electricity by 2010. These targets may or may not fit in with wider climate change targets, which makes them compatible with longer term options.

The main risk in making the transition to a long-run instrument would arise if the level of support of the transition measure was greater than the support that would be provided simply by putting a price on greenhouse gas emissions equal to international allowance prices. A further risk is that if a transition measure was not guaranteed a sufficient lifetime, it would not give investors confidence that they would be able to obtain a sufficient return on capital. The risks are not generally to renewable generation; if built, plants with no fuel costs would be expected to generate because of their low variable costs.

The way to ensure the greatest compatibility with the long-term greenhouse gas price signal is to either set targets that are consistent with the long-run expected response to an emissions price, or to continue a renewables support programme in the long run, alongside any price instrument.