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Draft Climate Change (Stationary Energy and Industrial Processes) Regulations 2009


Regulations made under section 163 of the Climate Change Response Act 2002 set out methods for registered participants to monitor and calculate their emissions from activities specified in Part 3 or 4 of Schedule 3 of the Act or part 4 of Schedule 4 of the Act. These activities are:

  • importing coal

  • mining coal where the volume of coal exceeds 2000 tonnes in a year

  • importing natural gas where the volume of natural gas imported exceeds 10,000 litres in a year

  • mining natural gas, other than for export

  • using geothermal fluid for the purpose of generating electricity or industrial heat

  • combusting used oil, waste oil, used tyres or waste for the purpose of generating electricity or industrial heat

  • refining petroleum where the refining involves the use of intermediate crude oil products for energy or feedstock purposes

  • producing iron or steel

  • producing aluminium, resulting in the consumption of anodes or the production of anode effects

  • producing clinker or burnt lime, resulting in calcination of limestone, or calcium carbonates

  • producing glass using soda ash

  • producing gold

  • producing cable using a nitrogen cure process

  • purchasing coal from one or more participants who mine coal where the total coal purchased exceeds 250,000 tonnes per year

  • purchasing natural gas from one or more participants who mine natural gas where the total natural gas purchased exceeds two petajoules per year.

Stationary Energy


A key change from the previous draft regulations is that the point of measurement for mined coal has been changed from the point of valuation to the point of sale as measurements of coal are already taken at this point. Using this point of measurement better meets the criteria outlined in ETS Bulletin No. 8 and eliminates the need for a stockpile adjustment for mined coal. Coal miners are now required to measure coal only at the point of sale, coal for their own use (ie, combusted before the point of sale) and coal gifted. Feedback is sought on this approach.

Coal stockpile adjustments for purchased and imported coal are provided for in a schedule to the regulations. The method for calculating a coal stockpile adjustment remains broadly the same. The Act requires separate reporting for separate activities in the NZ ETS (eg, importing and purchasing coal), and it is necessary to account separately for different classes of coal (eg, coal to which a DEF or UEF applies).

However, compliance costs of requiring a separate stockpile for different activities or classes of coal would be considerable for participants. Therefore, the new provisions for coal stockpile adjustments provide a way of assigning parts of a single stockpile to more than one activity or class of coal. Feedback is welcomed on the approaches used to address coal stockpile issues.

In response to feedback, DEFs for the coal sector have been independently reviewed by a specialist consultant and are revised in the draft regulations. Data provided by the consultant on the average emissions factor and distribution of emissions factors for each class of coal mined in New Zealand has been used to derive these revised DEFs. Both mined and imported coal now have the same set of emissions factors. This also provides consistency between the way imported and mined coal are treated in New Zealand’s Greenhouse Gas Inventory and the NZ ETS. The DEFs remain energy-based rather than set according to carbon content or mass, as was recommended in the SEIP Technical Advisory Group report published in October 2008.

A further consideration involved in the revision of the DEFs for the coal sector has been the provision made to apply for approval to use a UEF. Eligibility thresholds have been set for approval to use a UEF. It is expected that participants with emissions factors below the eligibility threshold for obtaining a UEF will apply for approval to use a UEF.

The result of such ‘adverse selection’ means the remaining participants to which DEFs apply will have emission factors that are greater than the average emissions factor for a specific activity. Therefore, it is necessary to set DEFs above average emissions factors for a class of coal to counter-balance the use of UEFs, and more accurately reflect the actual emissions from participants’ activities which will be using DEFs in emissions returns. Eligibility thresholds for UEFs and DEFs for the coal sector have been set at levels intended to deliver fiscal neutrality for the Crown and to minimise inequities for smaller participants. Further detail is contained in
Appendix 4.

It is intended that DEFs will be amended periodically. The time period for review will be, at a maximum, the time period for review of the Act. The first review of the Act must be concluded by the end of 2011. It is also intended that DEFs will be reviewed as and when better information on emissions factors exist, including the information gathered from UEF applications.

A number of submissions on the previous draft SEIP regulations commented on the provisions made for fugitive coal seam methane. Officials are aware that the high variability of coal seam properties in New Zealand means there are measurement and sampling issues, and safety issues involved in measuring fugitive coal seam methane emissions.

However, the Act includes a liability for fugitive methane emissions from coal mining to be included in the NZ ETS for coal mining participants. Consequently, the draft regulations retain a default process to use in calculating liability for fugitive coal seam methane emissions in accordance with the 1996 IPCC guidelines. Officials are aware that the properties of New Zealand coalfields will likely mean these IPCC default factors will differ from emissions from New Zealand mines. Further feedback is sought from coal miners on the treatment of coal seam methane in the NZ ETS, and how this can be best measured and reported.


In response to issues raised by submitters on the previous draft of regulations, and based on advice from an independent contractor, the method for calculating emissions from gas mining has been substantially revised.

The revised method is based on continuous measurements of gas volume and properties which effectively provides for unique emissions factors for gas miners. It is intended this method more accurately captures gas mining activities across the industry and provides clarity over how to account for the various emissions associated with gas mining.

A key principle underpinning the revised method is that measurement and reporting systems should be based on robust existing information systems where possible. Consequently, gas chromatographic analysis (GCA) at the point of sale forms the basis of the method for calculating emissions. The draft regulations specify ways in which data measured by or derived from GCA should be used to calculate and report emissions, which are intended to be broadly similar to those used in existing hydrocarbon accounting systems.

Standards for sampling and testing using GCA have been specified in the draft regulations to ensure consistency and quality of measurement by all participants. Feedback is sought on whether both smaller and larger participants can meet these standards and on the practicality of the method for smaller participants.

At present there are no verification requirements for the sampling and testing regime prescribed. However, consideration is being given to this and feedback is welcomed on what an appropriate verification regime might be for the draft method.

New definitions for ‘classes’ of gas are included in the revised method. These classes are intended to reflect the configuration of emissions from processing plants at the point of obligation ie, plants processing mined gas. The revised method requires all the ‘streams’ or ‘classes’ of gas exiting the processing plant to be accounted for.

The following schematic outlines this configuration and classes.

Gas processing plant

Some default emissions factors remain in the revised method. These provide factors for the non-CO2 emissions associated with eventual downstream combustion of gas, and a factor to enable provisions for storage adjustment. At present, there are no provisions to apply for approval to use a UEF for gas sector activities. However, using continuous measurement means that changes in gas properties over time are effectively accounted for.

A number of submitters commented on the provisions for ‘unaccounted-for gas’ (UFG) in the previous method. A new factor for ‘losses’ replaces this UFG factor in the revised equation. Losses from the transmission and distribution network and from UFG are accounted for in New Zealand’s Greenhouse Gas Inventory and form a part of New Zealand’s overall emissions liability. Due to the difficulty of measuring this, the revised method adds an amount for losses to each participant, which divides the total national losses by that participant’s share of national gas production, as specified in the annual report on New Zealand Energy Greenhouse Gas Emissions. This report is published annually in July or August at

The revised method for gas mining has led to changes in the method for opt-in gas sector participants to calculate their emissions. The point of measurement has changed to the point of sale. This makes reconciliation between obligation and opt-in participants simpler. However, only gas purchased by an opt-in participant can be subtracted from the emissions return of the obligation participant. The method requires the opt-in participant to report emissions using the same information as an obligation participant. This requires that the opt-in participant can access the required data. Feedback on this approach is welcomed.

A storage adjustment provision has been included for opt-in participants. A DEF has been used for this, but as the same factor is applied to natural gas going both in and out, the result should be effectively neutral.

The method and emissions factors for importing gas have also been reviewed by an independent contractor. No changes have been made to this method.

Officials are interested in discussing the changes to the gas mining method with participants during the consultation period.


In response to feedback from submitters and advice from an independent consultant, the classes of geothermal resource have been re-defined and now relate to specific geothermal plants, rather than geothermal fields. Consequently, plant-specific DEFs are used in these regulations. A DEF for ‘all other’ geothermal participants has been set at the highest relevant class. Current or future geothermal energy users without a plant-specific DEF will have to use this factor or apply for a UEF.

Feedback is welcomed on the revised geothermal classes and associated DEFs.

The regulations have also been revised to provide for differences in geothermal plant design that affect the workability of data collection and the method for calculating emissions. Different requirements apply to uses of geothermal steam (the majority of geothermal plants) and uses of geothermal fluid heat (for example the Tauhara Industrial Use Facility).

For uses of geothermal steam, the point of measurement has been changed from the wellhead to the separation point or mixing point where steam is delivered in multiple transmission pipelines. This is intended to provide for simpler and more accurate measurement of steam flow. As there is likely to be more than one steam measuring point for each plant, DEFs have been calculated as a weighted average of emission factors in steam flows.

Provisions have now been included in the UEF regulations for calculating emissions relating to condensate reinjected and geothermal fluid used in industrial heat. Approval to use UEFs can be sought by all users of geothermal fluid and steam. A threshold of 5 per cent divergence from the DEF has been set based on the uncertainty inherent in measurement and testing procedures.

Combustion of waste

There has been a complete rewrite of the SEIP and UEF regulations for calculating emissions from burning waste oil, used oil, tyres and waste for generating electricity or industrial heat. This is in response to feedback and is based on the advice of a specialist independent consultant.

Classes of waste and DEFs have been revised to provide greater clarity and align with the IPCC Good Practice Guidelines which form the basis of the New Zealand Greenhouse Gas Inventory.4 Biogas and biofuels are not included in the classes that these regulations apply to. Emission factors are also expressed in a different unit (tCO2-e/TJ). Many submitters on the previous draft regulations focused on combusting biomass materials, including waste wood. CO2 emissions from combusting biomass are not counted in these regulations as they are effectively covered under the forestry regulations.

However, in response to feedback, a separate method requiring the use of continuous monitoring equipment positioned within stacks has been included in the draft UEF regulations. Participants applying for a UEF for biomass combustion must use this method, but it may also be used by participants combusting blended or waste fossil fuels. This method still requires sampling and testing fuels to determine energy content.

A minimum threshold for combustion of biomass will be developed separately from a general threshold for waste combustion. An important principle of designing a threshold will be to ensure there is no disincentive for efficient use of wood waste as an alternative to fossil fuel use. Feedback on minimum thresholds is welcome.

The equation in the draft SEIP regulations relating to combustion of used tyres has been revised to clarify that the biomass fraction is not included in the emissions calculation. However, as CO2 from this biomass fraction is counted under the IPCC Guidelines, an adjustment has been included in the equation to calculate total emissions. Feedback is welcome on this proposed approach, including on the sampling and testing methods.


Regulations for refining activities remain unchanged from the previous draft of the regulations.

Opt-in participants

The point of measurement for coal and gas sector opt-in participants will be the point of sale. A consistent point of measurement for obligation and opt-in participants is necessary to ensure integrity of the overall scheme. Revisions to the data collection and emissions calculation requirements for opt-in participants have been made to reflect this change and the revised emissions factors. Feedback on this approach is welcomed.

Some submitters from the natural gas sector noted that, under the current opt-in provisions in the legislation, they would not be able to opt in. The legislation is based on buying natural gas from a gas mining participant, meaning that for some gas users, although their total use of natural gas is more than 2PJ, they cannot opt in for their gas use as some gas is bought from wholesalers rather than directly from gas mining participants. Although opt-in provisions for natural gas users would enable these users to manage their liabilities directly, there are considerable practical difficulties associated with adopting a model allowing for opt-in more than one step removed from the point of obligation. Amending opt-in provisions for natural gas users would require an amendment to legislation, rather than regulations.

Similarly, some geothermal submitters noted that they would like the option to opt in for their geothermal liability. Providing the ability for geothermal users to opt in would require an amendment to legislation. Officials do not consider that an ability to opt in for geothermal fluid use is required, as the point of obligation in the legislation is defined as the user of geothermal fluid, rather than the owner, and geothermal default emissions factors are defined at a very specific level. We welcome feedback on this approach; in particular, whether there are any specific issues involving determining liability for emissions from use of geothermal fluid where there is more than one user of the same geothermal fluid, for example one large user is downstream of another.

Industrial processes activities

Some amendments to the emissions calculation equations for industrial process activities have been made so that the amount of pure chemical substance used in each process (carbon, calcium oxide, calcium carbonate, magnesium oxide) is the key variable in the equation. This is a change from the previous regulations and is intended to provide for variation in input and production process without the need to obtain approval for a UEF. Further explanation of the rationale for this position can be found in the commentary on the UEF regulations below.

Standards and guidelines will be developed on how to measure total chemical content in the raw materials used in many processes. These will provide consistency of measurement between participants and certainty on how to complete an emissions return to comply with obligations under the Act. Officials welcome the involvement of participants in the development of these standards and guidelines. Details of how to participate in the process to develop these guidelines are outlined at the end of this document.

Additional industry-specific details follow.


The regulations now clarify that reducing agents for which an emissions charge has already been paid, and carbon inputs generating minimal emissions, should not be included in the calculation of emissions from producing iron or steel. In addition, the regulations have been changed to remove iron sand and iron ore from the emissions calculation, as officials understand there is no carbon contained in iron sand, and iron ore is not used in New Zealand. Therefore, there is no need for participants to record this information.

As the equation now multiplies total carbon content, rather than tonnes of reducing agent, the emissions factor for carbon used in steel production remains 3.67.


In response to feedback, regulations relating to the production of aluminium have been modified to clarify how information must be collected. No emissions factors are required for calculation of emissions from aluminium production as modifications have been made to the method, so carbon dioxide is directly estimated in accordance with the Aluminium Sector Greenhouse Gas Protocol.

Production of cement clinker or burnt lime

An additional variation has been added to the emissions equation for the production of cement clinker or burnt lime to account for emissions from partially calcined cement kiln dust (CKD). A CKD correction factor has been included in the regulations for participants to use for a manufacturing process where CKD is emitted. As data on CKD is very scarce, the default correction factor in the IPCC Good Practice Guidelines has been adopted. For processes where no CKD is emitted, this factor will not be used.

Glass production

No additional changes have been made to the method of calculating emissions from glass production.

Gold production

Officials are aware that not all of the limestone used in gold production causes emissions. However, further information is required to identify what specific proportion of limestone use results in emissions before a more accurate emissions factor can be included in the regulations. Feedback on the accuracy of the gold-mining emissions factor is sought.

Cable production using a nitrogen cure process

Following review of regulations by an independent party, it has been determined that the nitrogen used in cable production in New Zealand does not, of itself, generate greenhouse gas emissions. In light of this information, the regulations for cable production have not been amended at this stage. Further consultation with participants will be undertaken to progress this issue.

4. Intergovernmental Panel on Climate Change. 2000. Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories. J Penman, D Kruger, I Galbally, T Hiraishi, B Nyenzi, S Emmanul, L Buendia, R Hoppaus, T Martinsen, J Meijer, K Miwa and K Tanabe (eds). Hayama, Japan: IPCC National Greenhouse Gas Inventories Programme, Technical Support Unit.