Climate change policies – current issues in the electricity industry
In December 2008, the Federal Government released its White Paper on the Carbon Pollution Reduction Scheme (CPRS) and, shortly thereafter, released draft exposure legislation for the expanded Renewable Energy Target (Expanded RET).1
The White Paper noted that the stationary energy sector produces about 50 per cent of Australia’s greenhouse gas emissions and therefore presents the ‘greatest potential to deliver reductions’.2 Not surprising then, that the Australian Energy Markets Commission (AEMC) asserts that
[t]he key impact of the CPRS will be increased costs for carbon-intensive generation. This will potentially affect how existing generators operate, and change the economics of new investment in favour of lower-carbon (for example, gas) and zero carbon (ie wind) technologies. It will also increase prices in wholesale markets, and related contract markets.3
This paper explores some of the issues which the policy raises for the electricity sector, especially having regard to the world financial crisis (WFC).
What is the CPRS?
The proposed emissions trading4 scheme is a cap-and-trade system covering six greenhouse gases, but exempting certain sectors of the economy (around 25 per cent).
What is the Expanded RET?
The Federal Government will expand the Howard Government’s two per cent renewable energy target5 to 20 per cent by 2020 (an additional 45,000 GWh) per year.
Exposure drafts of the legislative amendments were released on 17 December 2008, and a discussion paper on the impact on electricity-intensive trade-exposed industries was also released in December 2008.
Generation
Generators required to purchase permits
Generators that emit over 25,000 tonnes of CO2-e6 per annum will be liable to acquire and surrender carbon pollution reduction permits (to be known as Australian Emission Units (AEUs)) equivalent to their actual emissions of CO2-e. Each AEU represents one tonne of CO2-e.
As a ‘strongly affected industry’, the coal-fired electricity generation sector will benefit from the Electricity Sector Adjustment Scheme (ESAS) (described below), and receive part of their requirements for AEUs for free.
The remaining AEUs (around 70 per cent of available AEUs) will be auctioned monthly, with the first auction taking place as early in 2010 as is feasible, that is, prior to the start of the CPRS in July 2010. Four ‘vintages’ will be auctioned so bidders may acquire permits for that year and three subsequent years. Each auction will be carried out as an ‘ascending clock’ auction whereby
the auctioneer announces the current price. Bidders indicate the number of permits they are prepared to purchase at that price. If demand exceeds supply, the auctioneer raises the price in the next round and bidders resubmit their bids. This process continues until the number offered is equal to or greater than demand. Bidders then pay the price from the previous round.7
For the 2011 and 2012 calendar years, the auction format will be ‘double sided’ allowing generators with an excess of free allocations of AEUs to sell them on the market (discussed in more detail below).
Where generators are short AEUs in the 2010 – 2011 compliance periods, they will be able to meet this shortfall by purchasing an unlimited number of AEUs at a government-set price of $40/tCO2-e.8 These AEUs will only be able to be purchased in the period between the final reporting date for the compliance year (31 October)9 and the final date for surrender of AEUs (15 December). This acts as a transitional price cap, ensuring the AEU price does not exceed $40/tCO2-e in the first two years of the scheme.
Treasury modelling suggests that, based on Australia’s unconditional commitment to reduce emissions by five per cent below 2000 levels by 2020 (the minimum emissions target), an initial permit price in 2010 will be around $23 and $35 in 2020.10 However the global financial crisis and recent CER price trends (see below) could influence this modelling.
Government-commissioned modelling had varied outcomes.11 Among these was that the volume of electricity generated by coal fired generators will decrease and that some black and brown coal generators may cease to generate earlier than their operational lives.
Ability to purchase CERs
Certain Kyoto Protocol emissions units (ie. Certified Emission Reductions12 (CERs)) can be used for up to 100 per cent of compliance obligations under the CPRS. As a result, the availability of international credits will potentially reduce the AEU price, especially since CER secondary market prices have fallen materially in recent times.13
This element of the proposal is quite important. The ability to purchase CERs creates a good deal more liquidity in the market, but could act to drive AEU prices down. In addition, it opens up a possible leakage of revenues from the auction system, thus reducing government revenues available to fund various compensation regimes proposed for sectors of the community.
Free permits for coal-fired generators
The Federal Government plans to provide $3.9 billion (value based on Treasury modelling) in free AEUs for coal-fired generators over the first five years of the CPRS. Under the ESAS, coal-fired generators were identified as the only ‘strongly affected industry’ and will therefore be the only ESAS recipients.14
On 10 March 2009, the Federal Government released the CPRS Exposure Draft Legislation (the Exposure Draft). Part 9 of the Exposure Draft sets out the criteria by which free AEUs are issued to eligible coal-fired electricity generators.
Free permits are granted in respect of individual generation assets and eligibility, in the form of a certificate, must be applied for by the person who owns, controls or operates the generation asset.15 The Australian Climate Change Regulatory Authority (the Authority) then makes a decision as to whether to grant a certificate of eligibility.
The eligibility criteria for ESAS assistance are:
- generated electricity in June 2007 (or qualified as a ‘committed’ project at 3 June 2007)
- connected to a major electricity grid (or will be connected), and
- use of coal for 95 per cent of its energy supply in the period from 1 July 2006 to 30 June 2007.16
In determining the level of assistance,17 the government will consider asset size (measured by the asset’s energy output between 1 July 2004 and 30 June 2007) and the level of emissions above the threshold of 0.86 tonnes of CO2-e per MWh.18
The higher a generator is above the threshold of 0.86 tonnes of CO2-e per MWh, the more assistance it will receive. There is a (reasonably complex) equation for the determination of how much assistance generators will be entitled to.19 Compensation is quite sensitive to emissions intensity. Some of the data used in modelling has been said to be based on rudimentary measurements. In addition, carbon intensity can vary with respect to the coal mined and coal characteristics can vary considerably even within a single mine.
For example, in its Green Paper submission, Tarong Energy indicated that its two complexes (1,843MW coal, plus 15MW gas) could generate annual GHG of 13 million tonnes. At a $20 per tonne price, annual permit costs would amount to $260 million.
Importantly, however, the free AEUs are likely to cover only a small part of the coal fired generators’ requirements—industry estimates suggest in the 15 per cent – 40 per cent range for those generators which have the higher emissions intensity and will be obligated to buy the greater number of AEUs.
Generators that receive free AEUs under the ESAS will be able to sell such permits at the ‘double sided’ auctions occurring in the calendar years 2011 and 2012 or through secondary markets. In the event that a generator closes down, it is unclear whether it will be required to relinquish AEUs allocated to it through the ESAS for production that did not occur. In contrast, the White Paper specifies that emissions-intensive trade-exposed (EITE) industries who cease EITE activity will be required to relinquish permits that were allocated to them for production that did not occur.
It is worth nothing that the draft legislation contains two caveats which could effect a coal-fired generator’s eligibility for ESAS assistance.
- The minister may make a windfall gain declaration—that a specified asset is ineligible for free AEUs in the 2014 and 2015 financial years—where generators are considered to be making a windfall gain from the scheme. In assessing whether to make a declaration, the regulator will consider whether there will be a projected long-term net revenue gain in respect of an asset, or if there is a projected long-term net revenue loss but the total value of assistance will exceed that projected loss.20
- ESAS assistance may be withdrawn where a generator’s nameplate rating (in megawatts) at 1 September of the relevant financial year is less than that registered under law, or in the event there is a reduction in the nameplate rating, the appropriate energy market operator certifies that there is unlikely to be a breach of power system reliability standards within two years of that nameplate rating reduction.21
Coal and gas suppliers exempt for sales to generators with an ‘OTN’
An Obligation Transfer Number (OTN) is an administrative mechanism that enables the Government to track fuel as it moves from the top of the supply chain to direct emitters. Under the CPRS, obligations are generally imposed on the upstream suppliers of fuel, rather than the users. This is intended to simplify calculation and compliance. However, suppliers can shift CPRS obligations to generators, who will be required to quote an OTN and report all coal or gas received. Query how this works for stations which own their own coal or gas.
Carbon cost pass-through
The White Paper states that ‘the legislation will not contain any provisions designed to override contracts to allow for pass-through of carbon costs’.22
Generators will be reviewing their hedge contracts (and PPAs where they exist) to determine whether pass through is permitted and how the cost associated with CPRS is calculated for this purpose.
Market contracting has trended to the short term anyway given the uncertainty with the scheme. For new contracts extending past 1 July 2010, generators will need to either estimate their CPRS cost and factor it into their price, adopt a pass through mechanism (difficult to provide for, but we understand a model is under development by Australian Financial Markets Association) or simply cut the base deal as before but require the retailer to buy the necessary permits.
Increased demand for gas
The government expects that the CPRS will materially increase the level of gas-fired generation and demand for gas transportation capability. A McLennan Magasanik Associates report predicts a tripling of gas consumption for electricity generation in the National Electricity Market (NEM) from 200 PJ to 600 PJ a year by 2018.23 This is sensitive to assumptions about gas prices and availability of capital for investment, among other things. Gas fired generation may also be hampered by the lack of free permits relative to coal for the first five years of the scheme.
The AEMC has said that the current regulatory framework is flexible and robust enough to cope with this fuel switching, but is inviting submissions.
Generation capacity
Assuming all existing generation capacity remains in service, capacity reserve levels in Victoria and South Australia in the period 2010 – 2011 are expected to be at or below minimum reserve levels. Indeed, following record Vic load levels and load shedding in the last week of January 2009, those minimum reserve levels may need to be re-assessed!
Significant issues remain concerning sources of new baseload generation in the NEM. Whether the market provides efficient price signals for investment has been a long standing controversy, now compounded by the WFC and CPRS.
There must be a risk that new plant will not be built fast enough even to cover basic load growth, let alone plant which may be retired for any reason, including CPRS. Notwithstanding the ESAS, there may be little incentive for owners of existing plant to commit to capital demands, thus shortening asset lives and reducing asset reliability.
Renewable connection to energy networks
The Expanded RET may, subject to the WFC, stimulate investment in renewable projects – expected to be mainly wind generation in the medium term. Such projects are often in remote areas where connection to existing transmission or distribution networks requires significant additional infrastructure. Serious questions exist, however as to the preparedness of transmission and distribution operators to make this investment due to the WFC and the outlook for regulated revenues following the AER’s determination of its approach to WACC.24
The AEMC has also flagged that issues may arise if large numbers of connection applications by different players emerge in the same areas.25
Who has to buy permits when more than one party is involved in a generator?
Under the White Paper, the corporate entity which is obligated to purchase permits under the CPRS on behalf of the emitting facility (eg, power station) will be the entity that has ‘operational control’ over that facility. The operational control test referred to in the White Paper is the same as the operational control test under the National Greenhouse and Energy Reporting Act 2007 (Cth) (the NGER Act), ie. the party with authority to introduce and implement operating, health and safety, and environmental policies for the facility.
Only one corporation can have operational control of a facility at any one time. If several parties are involved in the ownership and control of a facility and existing contracts do not clearly stipulate control, this could become a complex question of fact.
CCS
Carbon transferred to a carbon capture and storage (CCS) facility will not be counted towards the originating entity’s emissions.26 The White Paper recognises CCS as ‘one key technology that could allow coal to continue to play a major role in the world’s energy supplies in a carbon constrained environment.’27
Offshore CCS activities are governed by recent amendments to the Offshore Petroleum Act 2006 (Cth), which is now known as the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (Cth). The amendments established a system of offshore titles that authorise the transportation, injection and storage of greenhouse gas substances in geological formations under the seabed. Onshore activities are expected to be covered by state-by-state legislation.
Although there are a number of CCS demonstration projects underway, both domestically and internationally,28 CCS technology is not expected to be commercially viable until the carbon price is high enough to justify the investment. As an illustration, the European carbon price of €40 in 2008 and €67 in 2020 is expected to make CCS technology viable in Europe by 2020.29 The Australian carbon price (based on a five per cent target) is expected to be much lower, at $23 in 2009 and $35 in 2020.30 Companies are unlikely to invest in CCS in the interim as it will be much cheaper to simply purchase permits.
Transmission and distribution
Energy lost in transportation – no liability but reporting required
NEMMCO estimates that 10% of energy generated by a power station is lost by the time it gets to the customer.31
A transmission or distribution company will need to report under the National Greenhouse and Energy Report Act 2007 (Cth) (NGER Act) if:32
- the company controls a ‘facility’ that consumes 100 terajoules of energy, or
- the corporate group consumes 500 terajoules of energy.
All transmission assets that are under the overall control of the same corporation constitute one ‘facility’.33 The same applies to distribution assets.
Energy lost in transportation is considered to have been consumed and therefore counts towards the 100 and 500 terajoule thresholds.34 This definition of ‘consumption’ applies in the same way to unaccounted for gas. Importantly, transmission and distribution “emissions” for energy already subject to the CPRS on generation are exempted from the need to require the purchase of permits.35
Transmission and distribution players will be interested in opportunities for additional electricity connections and gas transmission expansions for new generation (should it emerge as the government expects). However, access to capital is an issue, particularly if the AER’s proposed framework for revenues is adopted.
Retail
The government expects the price of carbon pollution to be passed down the supply chain, to be reflected in the final price for a product.36 The Federal Government expects a five per cent target will result in household electricity prices increasing by 18 per cent.37 The renewable energy target (discussed above), will also impact electricity prices.
However the White Paper has flagged price regulation and contractual impediments as potential barriers to the efficient pass-through of CPRS costs to the ultimate consumers of energy. This could both impede the effectiveness of the scheme in providing signals to consumers and, importantly, it could impose material costs and risks on retailers.
Price regulation
Customers who have not changed retailer are subject to retail price cap regulation. They are charged a regulated price under a ‘standing contract’. Customers who have changed retailer are not subject to price cap regulation. They are charged a non-regulated price under a “market contract”. While retailers can offer market contracts at tariffs higher than the regulated price, they are unlikely to do so because customers will most likely prefer the lower regulated price. As a result, the regulated standing contract price acts as a benchmark price.38
The AEMC has observed that retail price regulation is not flexible enough to cope with increased and uncertain costs.39 The different state-based regimes are varied and some may prevent efficient cost pass through.40
Of course industry participants have sought the removal of price regulation for some time, and for a variety of reasons. This is the agreed position in the Australian Energy Market Agreement, and the White Paper recognises that ‘[c]ompetition and consumer choice in retail energy markets is the best way to achieve a cost-effective demand-side response and to protect consumers from being overcharged for the costs imposed by the Scheme.’41
Victoria is the only state which has removed retail price controls. In South Australia, the AEMC recently recommended that retail price controls be removed.42 In New South Wales, the AEMC was due to review price controls this year but the New South Wales Government has requested that the review to be deferred until 2011. The Federal Government continues to urge state and territory governments to ensure there are no regulatory impediments to passing through CPRS costs.43
If the states concerned do not remove price controls, mechanisms will need to be explored to build into the state price regulation processes to allow CPRS costs to be measured and incorporated in tariffs. On 6 February 2009, the Ministerial Council on Energy agreed to consider a proposal that the States which retain price controls would agree to provide mechanisms to pass through any increase in energy costs associated with CPRS.
This is an area where the devil is in the detail—pass through mechanisms may not accurately reflect the costs, leading to residual risk for retailers and ‘friction’ in translating the CPRS into price signals.
Contractual impediments
Terms of retail electricity supply contracts might prevent pass through of CPRS costs (as discussed above in the ‘Generation’ section)44. As discussed above, the legislation will not override contracts to allow for pass-through of carbon costs.
Market contracts may provide retailers with greater opportunities to seek to pass-through carbon costs. However, some contracts written before the form of the new scheme became clear and which extend past July 2010 may not permit pass through. For those that do, there is potential for dispute as to what can be passed through and how this is determined.
While the regulated standing contracts do not at this point allow for pass through, it is hoped that, as a result of the February 2009 MCE meeting, mechanisms will be adopted to ensure the regulated prices themselves will adequately capture any increased costs. Again, there is room for debate as to what these are.
Contracting behaviour
Retailers have tended to contract short so far, pending further details of the scheme. However, even after it is up and running this trend may continue. The AEU and CER markets may not provide much medium to long term liquidity and retailers may be reluctant to avail themselves of it given the potential for carbon prices to fall further. In addition, option fees and other costs in securing longer term contracts could prove a drain on working capital.
Retailer of Last Resort schemes
If pass through issues led to the failure of a retailer, the Retailer of Last Resort (RoLR) schemes may not prove to be effective in transferring customers to a new retailer. The schemes have never been tested and challenges may arise in the cost of sourcing wholesale electricity and prudential coverage, transfer of customer information and inconsistency between jurisdictional schemes.
Intersection between the world financial crisis (WFC) and CPRS – the perfect storm?
The extent of the WFC is unprecedented and will impact many different aspects of the implementation of the scheme. Some examples are:
| Cause |
Effect |
| Constrained access to capital (debt and equity) for new investment of any kind due to WFC – and desire for equity and debt withdrawal as part of global deleveraging requirement. |
Slower rate of transition to lower carbon intensity generation than that expected by the government.
Potentially a failure to build plant required to service growing energy requirements (a serious policy issue of its own).
Revised capital expenditure programmes may shorten asset lives, but also reduce reliability. |
| Need for debt capital to service generator debt commitments falling due in the next two years including financing the purchase of AEUs– before the details of the CPRS are known or the manner it will work in practice can be understood and while the WFC is a significant factor. |
Reduced availability of debt and increased cost (notwithstanding lower base rates).
Potentially shorter term facilities for generators—expiring before the end of the five year transitional period.
In some cases, standstills or restructures may result if new facilities are not available and equity holders cannot see a business case to provide more equity. |
| Additional risks for providers of equity and debt capital to assess, such as AEU requirements for individual generators, extent to which additional costs can be passed through the market (‘free’ AEUs may be only a modest portion of a generator’s requirements), extent of free AEUs and potential for revision mid term. |
Increased equity and debt buffers likely to be required to address risk. Programmes likely to be sought by lenders for managing emissions and AEUs, including trading in AEUs and other instruments to optimise assets and manage risk.
Higher equity and debt costs for a capital intensive industry. |
| Uncertainty about retailers’ ability to pass through CPRS costs to their customers (due to State government price controls), potential lack of availability of AEUs and CERs over the medium term or uncertainty about future price paths. |
May lead to retailers contracting short, which in turn may effect revenue certainty for generators, a factor in obtaining equity and debt finance and pricing. |
| White Paper provides some clarity – expectations of an ETS had been a large risk overhanging the market for some time. However, the above issues may have the effect that (1) the scheme may not achieve its intended effect (2) it may only do so at a cost far higher than expected (3) leakage of revenue to CERs or lower auction prices may place the government under budgetary pressure, given promised compensation to consumers (4) reduced reliability / blackouts could become a weighty issue. |
Possibility of abandonment or change—Senate deliberations may be just the beginning—thus continued uncertainty and risk of change. |
| Lack of equity and debt capital for transmission and distribution investment and prospect of poor returns due to the AER’s approach to WACC. |
May impede connection of what new generation there is, including renewable energy. |
This article was written by Robert Nicholson, Partner and Renee Garner, Solicitor, Melbourne.
Endnotes
1. Australian Government, Carbon Pollution Reduction Scheme: Australia’s Low Pollution Future, Commonwealth of Australia, 15 December 2008 (White Paper).
2. White Paper, 19-4.
3. Australian Energy Market Commission, Review of Energy Market Frameworks in Light of Climate Change Policies: 1st Interim Report, 23 December 2008 (AEMC Review). AEMC is currently reviewing whether the energy market framework is resilient to change in market behaviour arising out of the CPRS and the Expanded MRET. An interim report was released in December, and submissions are sought by 20 February 2009.
4. A more detailed description of the CPRS.
5. Further information on the Expanded RET.
6. ‘CO2-e’ means carbon dioxide equivalent. Each greenhouse gas is given a carbon dioxide equivalent based on its impact on the environment.
7. White Paper, 9-24.
8. To be increased by five per cent in real terms until 2014-2015 after which it will be removed.
9. In line with reporting under the National Greenhouse and Energy Reporting Act (Cth) 2007.
10. White Paper, 4-25.
11. The modelling was conducted by MMA, ACIL Tasman and ROAM Consulting
12. Others include Emissions Reduction Units (ERUs), Assigned Amount Units (AAUs) or Removal Units (RMUs).
13. Carbon Positive, ‘Global downturn hits carbon credits’, 16 January 2009.
14. The White Paper also considered, and rejected, the following industries: gas-fired and diesel-fired electricity generators, pumped storage hydro-electric generators, ‘captured’ coal mines, gas transmission pipelines, landfill waste and wastewater facilities, landfill gas electricity generators, the aviation and tourism industries, the community services sector, Government administration, and public transport: White Paper, Section 13.2.
15. CPRS Exposure Draft Legislation – section 177.
16. CPRS Exposure Draft Legislation – section 181.
17. Each certificate of eligibility sets out an annual assistance factor.
18. ‘CO2-e’ means carbon dioxide equivalent. Each greenhouse gas is given a carbon dioxide equivalent based on its impact on the environment.
19. This formula is set out at section 182 of the CPRS Exposure Draft Legislation.
20. CPRS Exposure Draft Legislation, section 187.
21. CPRS Exposure Draft Legislation, section 189.
22. White Paper, Section 15.5.
23. AEMC Review, 12.
24. Australian Energy Regulator, Proposed Statement of the Revised WACC Parameters (Transmission) and Proposed Statement of Regulatory Intent on the Revised WACC Parameters (Distribution), 11 December 2008.
25. AEMC Review, 34.
26. White Paper, Section 6.7.
27. White Paper, xl.
28. Refer to the C02CRC website for a list of Australian CCS demonstration projects.
29. Mark Davis, ‘It takes CO2 to Contango’, Point Carbon, July August 2008, 18.
30. White Paper, 4-25.
31. NEMMCO, An Introduction to Australia’s National Electricity Market, 6th edition, June 2008, 18.
32. NGER Act, s 9.
33. National Greenhouse and Energy Reporting Regulations 2008, reg 2.20.
34. National Greenhouse and Energy Reporting Regulations 2008, reg 2.23.
35. White Paper, 6-7.
36. White Paper, Section 15.3.
37. White Paper, 17-3.
38. AEMC staff paper Current Arrangements for Energy Retailing, 23 December 2008, 13.
39. AEMC Review, 50.
40. AEMC Review, 53.
41. White Paper, 15-13.
42. AEMC, Review of the Effectiveness of Competition in Electricity and Gas Retail Markets in South Australia, Second Final Report, 18 December 2008.
43. White Paper, 15-13 – 15-14.
44. White Paper, Section 15.3.2.
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