Such entities include electricity generators (direct emissions), gas producers (attributable emissions), fuel suppliers (attributable emissions), mining (fugitive emissions) and industrial processes (direct emissions and obligations on “upstream synthetic gas importers”).
Such entities will need to purchase a carbon permit for each tonne of greenhouse gas emissions for which they are responsible under the scheme.
Some assistance by way of free permit allocation is proposed for some trade exposed emission-intensive industries.
The cost impact on scheme participants is estimated at $8.4 billion if carbon permits are $20 per permit.
Companies affected by the proposed scheme should act now in order to minimise the cost impact and to prepare for carbon trading.
Contracting relationships
Entities with scheme obligations will suffer a carbon cost equal to the carbon permit price multiplied by the number of permits they will need to buy and surrender annually.
These entities should check their contractual relationships to determine whether the carbon cost can be passed through to their customers. In many industries contracts for the sale of the emission-intensive products may be long term and the price mechanism may restrict a pass-through of carbon costs.
In the electricity industry, for example, although the electricity is sold on a wholesale sort market, generators often have derivative contracts to swap the floating spot price for a fixed price. Such derivative contracts contain a “tax” adjustment clause, which refers to a “carbon cost” but this is referable to a carbon cost imposed on electricity.
The scheme imposes a cost on emissions, not on electricity, and therefore the carbon cost resulting under the scheme would not be able to be passed through under that clause.
In the electricity industry the carbon cost would increase the spot price after the scheme commences. Generators entering into derivative contracts before the scheme starts, which span the introduction of the scheme, may therefore seek to include provisions in their derivative contracts to pass through the carbon component, by an increase in the fixed price.
Once the carbon price is able to be determined, following the announcement of the permit caps and future cap trajectories, the prices of derivative contracts can reflect the anticipated carbon price.
The issue may only be temporary in the electricity industry.
In the gas and coal industries sales contracts tend to be relatively long term with pricing mechanisms comprising several components.
There is usually some type of pass-through clause allowing specified categories of additional costs to be passed through. The wording of these should be checked and revisions sought if necessary.
The scheme may impose liability on one entity in a corporate group, but the costs pass-through clause may be limited to passing through the contracting entity’s costs.
In such cases it may be necessary to assign the contract to the entity with the scheme liability.
Preparing for carbon trading
Each year permit requirements up to the cap will be auctioned by the federal government, possibly quarterly and including a portion of the following year’s permit requirements in the final quarter of the current year.
Funding the acquisition costs will require early attention.
Secondary markets, including a derivatives market in financial products, are anticipated to develop.
Multiple purchase options are therefore available.
Some of these may (particularly derivatives) require the holding of an Australian financial services licence. The government’s preferred position, set out in the green paper, endorses making carbon permits financial products – in their own right – in order to better regulate the carbon permit markets.
All of the other environmental products currently traded in Australia (including renewable energy certificates, New South Wales greenhouse gas abatement certificates and Queensland gas electricity certificates) are not financial products per se. Nor are the European Union or New Zealand permits.
It is not clear why carbon permits should be treated differently to other environmental products. In particular, there is little likelihood that retail clients will purchase carbon permits and carbon permits will be subject to regulation as financial services if the contracts for permits are themselves “derivatives”.
Contracts will fall within the definition of derivatives in the Corporation Act 2001 if the pricing mechanism is referable to a carbon market price, a cash settlement option at a carbon market price is included or the contract swaps a carbon market price for a fixed price.
The over-the-counter market in derivatives requires participants to hold an Australian financial services licence (AFSL) unless an exemption applies. An exemption is applicable if the dealing is to manage the entity’s own financial risk and the dealing is not a significant part of the entity’s business.
For some entities their carbon portfolio is likely to become a significant part of their business – in which case an AFSL will be required. Also, if an entity manages a carbon portfolio which involves regularly offering prices to third parties, that activity may constitute “making a market” in carbon permits, in which case an AFSL will be required.
The AFSL process can take four to 12 months and requires the engagement of suitably qualified personnel and the introduction of policies and procedures designed to manage the derivative trading risks.
The process does, however, result in the entity being better prepared to run its carbon trading portfolio, and investors are therefore likely to view this as a positive benefit to the organisation.
NGERS obligations
Affected entities are also likely to be subject to reporting obligations under the National Greenhouse and Energy Reporting System (NGERS), which commenced on July 1, 2008.
This requires entities with direct emissions at a single facility which exceed 25,000 tonnes of greenhouse gases, along with direct emissions at various facilities within the group’s control exceeding 125,000 tonnes of greenhouse gases, and large users of electricity, to measure and report on their emissions.
Registration under the system is required by August 21, 2009 and data collection needs to commence from July 1, 2008.
Most companies in these categories may already have systems in place for reporting under other programs and these should now be checked for compliance with NGERS requirements.
The issues discussed above all need early attention in order that a liable entity is best placed to manage its carbon obligations and take advantage of carbon trading opportunities.
Fiona Melville is a partner in energy and resources with law firm Johnson Winter & Slattery. Contact at fiona.melville@jws.com.au
Emission-intensive industries specified in the green paper include:
Group 1 – Aluminium smelting, lime production, cement clinker production, integrated steel manufacturing, silicon smelting; and
Group 2 – Ceramic product manufacturing, alumina refining, chemicals manufacturing, non-metallic mineral product manufacturing, pulp and paper manufacturing, non-ferrous metals smelting.
2 Assistance, by way of free permits, is proposed with a 90% allowance to Group 1 industries and a 60% allowance to Group 2 industries.
Important Disclaimer: The material contained in this article is comment of a general nature only and is not and nor is it intended to be advice on any specific professional matter. In that the effectiveness or accuracy of any professional advice depends upon the particular circumstances of each case, neither the firm nor any individual author accepts any responsibility whatsoever for any acts or omissions resulting from reliance upon the content of any articles. Before acting on the basis of any material contained in this publication, we recommend that you consult your professional adviser.
