3. Electricity allocation factor

3.1 Introduction

The NZ ETS will increase the costs of generating electricity from fossil fuels and geothermal sources. Although fossil fuels make up a relatively small proportion of total electricity generation in New Zealand (34 per cent of the total in 2008), they have a larger impact on the average wholesale price under New Zealand’s competitive electricity market.

A number of energy-intensive firms will face higher costs of production because of the electricity used in their production. Work was undertaken in 2008 by the Stationary Energy and Industrial Process Technical Advisory Group (SEIP TAG) on the expected increase in electricity price as a result of the introduction of the NZ ETS. This was used to derive an emission factor that would take account of this price increase. The factor they proposed was 0.52 tonnes of CO2/MWh.

This estimate was based on modelling to estimate the price impact of a range of plausible emissions prices. The proposed factor is the median of the range of outcomes. A summary of this analysis is available on www.climatechange.govt.nz.

The consultation document proposed that the same approach be used regardless of whether the electricity is generated on site, via distributed generation or purchased from the grid. The only exception will be for very large users (greater than 2000 gigawatt hours per annum at a single facility) where a specific contract price for electricity will have a different impact. In this instance, the Government retains the option to set a specific electricity allocation factor (EAF).

The consultation document also proposed to use a different EAF for decisions on eligibility – 1 tonne CO2 per gigawatt hour. This is the EAF used under the proposed CPRS in Australia and reflects the Australian electricity mix. Using this EAF will help to ensure equivalence in eligibility decisions between the New Zealand track and the Australian track, if used in the future.

Question 3 in the consultation document asked about the EAF and Question 4 asked about activities with high electricity use. Eighteen submissions raised issues on the EAF and activities with high electricity use. Submissions on the EAF were received from Canterbury Woolscourers, Carter Holt Harvey Woodproducts, Parliamentary Commissioner for the Environment, Pan Pac Forest Products, The New Zealand Refining Company, Ballance Agri-Nutrients, Evonik Degussa Peroxide, Norske Skog Tasman, Meat Industry Association, Winstone Pulp, Westland Milk Products, SCA Hygiene, Fonterra, Fletcher Building, Rio Tinto Alcan NZ, Holcim, Carter Holt Harvey Pulp and Paper, and Business NZ.

3.1.1 Summary of issues

Holcim, Meat Industry Association, Norske Skog Tasman, Evonik Degussa Peroxide, Fletcher Building, Westland Milk Products, and Business NZ proposed that the EAF be higher than 0.52 NZU/MWh. To support their contention, many cited the analysis commissioned by the Major Electricity Users’ Group (MEUG) from Professor Andy Philpott and Tony Downward of Stochastic Optimization Ltd (SOL) which suggests that because of imperfect competition in the electricity market, prices will be higher than short run marginal costs. SOL explicitly modelled uncompetitive behaviour using data from 2008 to suggest that the price impact would be equivalent to an electricity emission factor of between 0.61 and 0.69 NZU/MWh.

The PCE submitted that the EAF should be lower than 0.52 NZU/MWh. It estimated the impacts on the basis of the emission intensity of the marginal (in a new-build sense) new-entrant generators, rather than by estimating the impacts on the costs of the marginal (in an operational sense) existing generators. PCE further suggested that the extent of the price impact would vary substantially by the different times of day and year.

Norske Skog Tasman also submitted that the modelling behind the 0.52 factor chosen by SEIP TAG was based on modelling with an assumed carbon price of $40tCO2 but that the same modelling exercise identified that for lower carbon prices, the effective emissions factor would be greater. During the transition phase, the price of carbon is effectively capped at $25tCO2e and users will be subject to a 2:1 surrender obligation until the end of 2012 – ie, giving an effective CO2 price cap of $12.5/tCO2e. Norske thus argue that during the transition phase the 0.52 factor is too low.

The EAF of 0.52 tonnes of CO2/MWh does not affect whether an activity will receive 0%, 60% or 90% allocation. For determining the eligibility of an activity, a factor of 1 tCO2/MWh was proposed based on the factor used in the CPRS (Emissions Rule 9). This was supported by all submitters who commented on it, except for the Parliamentary Commissioner for the Environment.

3.1.2 Analysis

The proposed EAF was based on extensive modelling work on the impacts of emissions prices on electricity prices undertaken for the SEIP TAG during 2008.

The group agreed to a modelling framework involving both long-run and short-run approaches to provide a recommendation for the period to the end of 2012, when it should be reviewed. The group recommended the use of an electricity allocation factor of 0.52 tCO2/MWh until 2013 based on modelling the impacts on future electricity prices by Tom Halliburton of Energy Modeling Consultants (EMC).

The EAF analysis for beyond 2013 will need to be reviewed before the end of 2012. It is possible further analysis could be undertaken as part of the review of the NZ ETS in 2011.

Suggestions to alter the EAF raise questions about the approach used, particularly the assumptions regarding perfect competition in the market, and the interaction between the key drivers of electricity prices (ie, new-entrant long-run marginal costs versus existing producers’ short-run marginal costs). The answers to these questions are IN PART a judgement call and will involve a range of assumptions that will need to be taken into account in any future analysis.

The new analysis provided by MEUG and others results in a higher EAF, but is based on data for an historical year. The analysts that undertook the work do not know whether an analysis using their model, but for the historical period used to derive the 0.52 factor, would lead to a number higher or lower than 0.52. At the same time, others have suggested that the 0.52 allocation factor may be too high, and this includes the results of recent work by Concept Consulting to examine the impact of electricity contracts on the pass through of emission costs. 6

Together this means there is no clear basis for adopting an alternative number to that recommended by the SEIP TAG.

3.1.3 Decision

The Government recognises that a number of legitimate arguments have been submitted for both higher and lowers EAFs, but notes that no clear basis for an alternative number has been proposed. To explore fully the implications of the issues raised would require another considerable modelling exercise, and is likely to require a range of assumptions.

The Government’s clear priority is to get the allocation process up and running to give industry certainty as soon as possible. The proposed EAF was based on extensive modelling work on the impacts of emissions prices on electricity prices undertaken for the Stationary Energy and Industrial Processes Technical Advisory Group (SEIP TAG) during 2008.

Therefore, the Government believes that an EAF of 0.52 is a sufficiently robust approach for determining allocative baselines in the short term. The Government recognises that the EAF will need to be reviewed before the end of 2012, to ascertain its appropriateness beyond 2013. In making this decision, the Government notes that the transition phase, which will run to the end of 2012, will substantially reduce the impact of the emissions price pass-through in electricity prices.

The Government proposes to maintain a factor of 1 tCO2/MWh for determining eligibility of activities. This will also need to be reviewed before the end of 2012.

6 Concept’s conclusions were based largely on (1) the assumption that contract prices reflected long run marginal costs and that, irrespective of the price of CO2, these would be likely to reflect the costs of geothermal generation over the period in question—we note that this was an issue that the SEIP TAG debated at length and that Concept Consulting is taking a particular stance on this issue that is not shared by many on the SEIP TAG and (2) that the 0.52 factor was based on the average shape of demand for NZ as a whole, as opposed to that which applied to the industrial users.