Chapter 5
Energy Use and Supply (Part a)
… learning about energy efficiency should be as necessary in
our society as the capability to swim, ride a bicycle, drive an automobile
or operate an automatic teller machine. [1]
Introduction
5.1 Emissions from the production and consumption of energy are the primary
source of Australia's greenhouse gas emissions and emissions growth. [2]
Overall, emissions from the energy sector (including transport) accounted
for 79.6 per cent (362.9 Mt) of total national net CO2-e emissions in
1998. This represents a 62.4 Mt CO2-e (21.1 per cent) increase between
1990 and 1998, of which a quarter occurred in 1997. [3]
5.2 The energy sector of the NGGI is made up of stationary sources, fugitive
emissions and transport. Stationary energy is the focus of this chapter
and includes emissions from energy generation, energy used in manufacturing
and construction, as well as the commercial and residential use of energy.
5.3 Stationary energy was the major contributor to emissions in 1998,
at 56.8 per cent of total national emissions. Between 1990 and 1998, emissions
in this sector increased by 24.3 per cent and, in the period 1997 to 1998
alone, increased by 7.6 per cent. [4]
5.4 This increase far exceeds the rate of increase of other sectors.
Most of the increase in emissions in stationary energy is attributable
to the generation of electricity, which has recorded an increase of 30.6
per cent since 1990 and 10.3 per cent since 1997. [5]
This is a disturbing trend, and it is clear that constraining energy emissions
will be a difficult task in Australia's abatement effort.
5.5 In 1998, the National Greenhouse Strategy (NGS) predicted that, without
abatement action, energy emissions will increase by a further 64 Mt CO2-e
by 2010, and that assuming the effects of all current policies (including
market reforms and the Greenhouse Challenge Program), emissions will increase
by a further 28 per cent by 2010 - 20 per cent more than the overall increase
allowed under Australia's Kyoto target. [6]
5.6 Even these predictions, made two years before the 1998 Inventory
was completed, may be too conservative. The Electricity Supply Association
of Australia has predicted that demand will rise by at least 53 per cent
over 1990 levels by 2010, resulting in an emissions increase of 41 per
cent by 2010. Pacific Power told the Committee that, if emissions were
not constrained, the electricity industry would reach 150 per cent of
1990 emissions levels by 2010. [7]
5.7 Electricity emissions alone are responsible for half the increase
predicted by the NGS between 1990 and 1998. Since the introduction of
the National Electricity Market the emissions intensity of electricity
generation has also increased. Given this and increasing consumption,
it is possible that annual increases in the order of 15 Mt a year after
1997 will be the norm until at least 2010. This would see the 64 Mt increase
predicted by the NGS exceeded by 2001, and an increase of 135 Mt, or 80
per cent of 1990 levels, by 2010. The only policies currently in place
to address this are the mandatory 2 per cent renewables measure, which
may reduce emissions by between 4 and 5.5 Mt by 2010, and efficiency standards
for fossil fuel generation, which may reduce emissions by 4 Mt by 2010.
[8] However, these reductions are small in comparison
to projected increases.
5.8 Australia's high energy emissions are a legacy of two main factors:
the high dependence on cheap domestic sources of fossil fuel, especially
coal, and recent energy market reforms which have seen electricity generation
based on the highest carbon-content fuels become the most price-competitive
in the new deregulated market.
5.9 Since 1995, national energy markets have been subject to widespread
microeconomic reform, which, while primarily designed to create greater
competition and reduce costs, was also expected to deliver greenhouse
benefits in addition to those flowing to consumers. However, the reforms
have had many perverse outcomes including a dramatic increase in greenhouse
emissions.
5.10 In theory, micro-economic reform is intended to open energy markets
to greater competition, breaking down the market power of incumbents and
thus creating opportunities for alternative fuels and technologies. However,
the Committee heard much evidence that the new NEM discriminates against
gas as a fuel and against the entry of new players and more sustainable
technologies. It has also had the perverse effect of making the most emissions-intensive
fuel source - brown coal - the most price competitive.
5.11 During its inquiry, the Committee canvassed the views of a large
range of energy players: consultants, generators, distributors and retailers,
cogenerators, renewable energy generators, regulators and government officials.
While offering a variety of views, they all agreed on the high emissions
outcomes of current energy market changes and the importance of this sector
both to the economy and to Australia's ability to meet its current and
future commitments under the UNFCCC. Common themes which emerged from
evidence were:
- the perverse effect of increasing competition in electricity markets
which meant that the highest emissions intensity fuel sources (brown
and black coal) were also the cheapest;
- the barriers to entry to less emissions-intensive fuels and forms
of generation, particularly renewables such as wind and solar;
- the need for proactive research and development, commercialisation,
and tax and investment strategies for renewable energy technologies,
both to reduce domestic emissions and take advantage of substantial
future export potential;
- problems in the pricing of transmission services, which were perceived
to bias large remote generation at the expense of local or distributed
sources such as cogeneration or small scale renewables;
- the way that current market conditions were encouraging inappropriate
new capital investment, with a number of new coal-fired power stations
being planned at the same time as plans for less emissions-intensive
alternatives, such as gas, were being shelved;
- the potential impact of market distortions such as long term fixed
price supply contracts; and
- the fears of some industries that increases in the cost of energy
would undermine their position, particularly in relation to international
competitors.
5.12 Witnesses also proposed and discussed a number of solutions and
policies, although there was a diversity of opinion on the best options.
Suggestions included:
- an expansion of existing voluntary programs such as the Greenhouse
Challenge Program to take in more sources and energy players;
- the removal of market distortions such as fixed price contracts, biased
transmission pricing, and grid-access problems for small-scale solar
and other renewables;
- changes to transmission pricing to remove biases against cogeneration
and distributed generation;
- the expansion of New South Wales' `Green Power' program nationwide,
under which consumers can pay a premium for electricity sourced from
renewables;
- the introduction of a mandatory target for the sourcing of electricity
generated from renewable sources (legislation was introduced in the
Parliament in July 2000 to this effect and was being debated in the
Senate as this report was tabled);
- the use of the taxation system, and grants for research and development,
as a further spur to the development of renewable energy technologies;
- the use of Commonwealth environmental powers to promote wiser investment
in power generation, possibly through the establishment of greenhouse
emissions as a `trigger' for Commonwealth environmental impact assessment
under the Environment Protection and Biodiversity Conservation Act
1999 (EPBC Act); and
- the introduction of a mechanism to price carbon, either through a
carbon tax or a market-based system of tradeable emissions permits (`emissions
trading'), which would have the effect of making less emissions-intensive
and renewable generation more price competitive.
5.13 A range of existing local, state and Commonwealth programs also
received comment, including, efficiency standards for power generation,
licence conditions, renewable energy development and commercialisation
programs, gas market reform, and energy efficiency and demand management.
Background to the Reform Process
5.14 Energy market reform began after the 1993 Hilmer National Competition
Policy Review and a 1991 decision by the Council of Australian Governments
(COAG) to improve competition in the energy sector. In 1995 the Competition
Policy Reform Act established a new Part (IIIA) of the Trade Practices
Act which provided a right of access to `essential facilities' including
national monopoly infrastructure such as electricity transmission and
gas pipelines. In 1991 COAG agreed to replace distinct state electricity
markets with a national electricity market (the NEM) and to separate monopoly
and contestable elements. While Western Australia could not be interconnected
to the NEM it also resolved to pursue reform.
Electricity
5.15 The basic principles underlying electricity market reform were that:
- generators should compete for the right to supply electricity (which
it was hoped would reduce prices and accelerate other efficiencies);
- there should be open access to the grid for new generation (which
would ideally allow for the introduction of new technologies and forms
of power); and
- customers should be free to choose who supplies their electricity
(which could also facilitate the take-up of less emissions-intensive
power).
5.16 There were four key elements of electricity reform:
- industry restructuring through the separation of generation and retailing
(which are to be open to new entrants and competitive pressures) from
the `natural monopolies' of transmission and distribution;
- the introduction of `competitive neutrality' through the corporatisation
of state and territory owned utilities, with the aim of placing them
on equal footing with private sector competitors, subject to corporations
law and other market constraints;
- price regulation (in advance of full customer choice of supplier)
to ensure that legislated monopolies cannot exercise market power to
the detriment of consumers; and
- the introduction of the NEM, which began operation in August 1998
with Victoria, NSW and the ACT, and South Australia from May 1999, will
broaden to include Queensland in 2000 and Tasmania in 2002. Distance
precludes the participation of Western Australia and the Northern Territory.
[9]
5.17 The rules for the operation of, and participation in, the NEM are
contained in the National Electricity Code (NEC), which is developed,
monitored and enforced by the National Electricity Code Administrator
(NECA). The National Electricity Market Management Company (NEMMCO) operates
the physical market for electricity. [10]
5.18 The NEM incorporates state-owned and private sector utilities alike.
Victoria privatised its electricity industry during the early 1990s for
approximately $30 billion. Prior to the sale the State Electricity Commission
of Victoria (SECV) was broken into ten separate retail, distribution and
generation businesses and sold separately. These include the grid operator
Powernet Victoria, the distributors CitiPower, Solaris, United Energy,
Eastern Energy and Powercor, and the generators Loy Yang Power, Hazelwood
Power, Yallourn Energy, Ecogen Energy and Hydro Victoria. In December
1999, South Australia began its privatisation program with the sale of
the distribution and retail businesses of ETSA to the Hong Kong-based
Hutchison Whampoa for $3.5 billion. [11]
5.19 NSW has not yet privatised its electricity industry but has undertaken
extensive corporatisation and industry restructuring along the lines of
other states and territories. During the 1990s, the NSW Electricity Commission
was restructured into separate transmission, generation and retail businesses.
Transgrid operates the wholesale market, transmission and system control;
generation is split between Pacific Power, Delta Electricity and Macquarie
Generation, and distribution between MetNorth Energy, Integral, Northpower,
Advance, Australian Inland and Great Southern Energy. [12]
5.20 In sum, there are now some 12 major generation companies producing
electricity for the wholesale market, plus a few smaller independent generators
and other producers associated with large minerals projects. Within Victoria
and NSW alone there are 43 retailers. [13]
This situation, along with the bidding rules for the NEM, has produced
intense price competition which has forced very large falls in prices
- to below marginal cost in some circumstances. The existence of fixed
price (or `vesting') contracts between some generators and customers/retailers
continues to limit the free operation of the NEM and has also kept prices
low. These price levels have increased the proportion of electricity produced
by the most greenhouse intensive generators (those using brown coal or
lignite) and is acting as a barrier to entry for more sustainable energy
technologies.
Gas
5.21 The reform of natural gas markets will also bear on the extent to
which gas can achieve greater prominence as a fuel for electricity generation.
To date this has been very limited, due to both the perverse impact of
electricity reform and the higher prices of gas in current markets. While
gas reforms are expected to lead to increased competition and lower prices,
in the absence of mechanisms which price emissions, its use in electricity
generation is likely to remain limited.
5.22 Gas market reform aims to introduce greater competition into a structure
in which `natural monopolies' over pipelines and distribution have historically
been in place, and production has been limited to single joint-ventures
extracting gas from a single basin controlled by state government. COAG
resolved in 1994 to promote retail competition and to develop an integrated
national gas market by allowing third party access to pipelines, with
the hope that this would stimulate further investment in exploration and
development. These principles have been placed into a national access
regime, set in state law, although efforts to promote greater competition
at the production end are ongoing. Central to this is the development
of an interconnected pipeline network. Since 1994 there has also been
a substantial disaggregation of gas businesses, and some privatisations,
creating competing transmission, distribution and retailing businesses.
[14]
The Emissions Impacts of Electricity Reform
Price competition in the NEM
5.23 Pacific Power explained how the electricity market reforms were
producing negative greenhouse outcomes:
The electricity market is unhelpful, because the reforms are based
on an electricity market that is scheduled on their marginal costs.
It does not directly create an environment where emissions are minimised.
It creates an environment where the lowest cost of generation is developed.
That ignores the capital cost of the plant and also ignores the emissions…
the lowest cost fuel, brown coal, produces the highest emissions. Therefore,
there are certainly some challenges there in getting emissions down
if the market was left to its own devices. [15]
5.24 The Electricity Supply Association of Australia (ESAA) confirmed
this diagnosis:
The competitive wholesale electricity market drives purchasers of electricity,
who in the first place are the retailers of the electricity, to pursue
the cheapest available electricity. The cheapest available electricity
by and large is coal-fired, and that is why in the recent past in Australia
there has been an increase in the use of coal and, therefore, of course,
an increase in emissions. [16]
5.25 The Australia Institute's Dr Clive Hamilton suggested that the NEM
has created intense competitive pressures which were driving prices down:
When the competitive electricity market was developed and came into
play in the early to mid-1990s, there was a view amongst energy experts
that it would release some of the constraints on the development of
gas-fired generation and would therefore be positive from a greenhouse
point of view. Because of the way the competitive electricity market
is operated, along with the process of privatisation of generation and
distribution assets, particularly in Victoria, what we have seen is
coal-fired generation engaging in an extraordinary price cutting war
in order to try and win market share. [17]
Barriers to gas and renewable sources
5.26 A significant impact of the NEM has been increased barriers to entry
for the less emissions-intensive gas-fired generation and renewables.
Dr Hamilton explained that:
It has been more difficult for gas-fired generation to penetrate the
market because it is so intensely competitive. Those pressures ought
to ease, but there is still a very strong place for policy measures
to promote low emission forms of generation, particularly gas, and zero
emission forms of energy use, notably renewables and energy efficiency.
Of course, there are very good economic arguments for that, given the
lower external costs associated with those forms of energy. [18]
5.27 Pacific Power explained that even though the long-run costs of coal-fired
and gas-fired generation were similar, market pressures were working against
gas:
The use of gas as a fuel instead of coal has the potential to reduce
greenhouse gas emissions, as it has a lower greenhouse gas intensity
than coal. The emissions from new gas plant would be around 40 per cent
of those from black coal plant and 30 per cent of those from a brown
coal plant. Significant emissions savings could also be achieved by
burning gas in existing coal-fired plant.
In economic terms, the capital costs of gas-fired plant are lower than
for coal-fired plant, but the fuel costs are higher. This results in
long run costs for both types of plant being similar. However, because
the cost of gas could be two to three times that of coal, the marginal
price of gas generation is much higher than that from coal. Consequently,
the construction of a gas-fired plant without a long term contract for
the output is unlikely to occur in the competitive electricity market.
[19]
5.28 Pacific Power has had first-hand experience of this market discrimination
against gas, having had to defer a major gas investment that was to have
been their major initiative in the Greenhouse Challenge Program:
Pacific Power considered at the start of the [Greenhouse Challenge]
Program that a gas-fired combined cycle plant would be commercially
viable by around the year 2000. To this end, preliminary design and
detailed environmental studies were carried out for a 400MW plant at
Wollongong and Development Consent was gained. That particular plant
would have produced electricity with approximately 1,300,000 tonnes
of carbon dioxide emissions each year less than the equivalent amount
of electricity from NSW coal-fired plant. This was the principal initiative
in Pacific Power's Greenhouse Challenge agreement.
Due to current conditions in the electricity market, and the introduction
of new coal-fired plant in Queensland, this plant is unlikely to proceed
for several years. It could be justified on environmental grounds only
if the mix of policies were in place to create the market conditions
that would enable the sale of the output. [20]
5.29 The market ascendancy of coal may also be placing large gas augmentation
and supply projects, such as the planned PNG pipeline, in some doubt.
Chevron Services Australia, which is developing the PNG gas project, has
opposed the licence applications for new coal-fired power stations at
Millmerran and Kogan Creek in Queensland, and stated in its submission
that:
What Governments have before them is a choice. It is a choice between
the new PNG gas project on the one hand and more coal-fired power stations
on the other. The Committee should appreciate that the economics of
the PNG gas project depend upon what access it secures to power generation
markets in Queensland. If that access is pre-empted by licensing of
any more coal-fired stations, the project fails. [21]
5.30 AGL, which will build, own and operate the pipeline from PNG, was
also concerned about the potential impact of new coal power developments
in Queensland on that project:
We see the coal-fired power stations as being a challenge, certainly
a hurdle, to the pipeline's future development. We are not really in
a position to… say it will be one or the other. But certainly it
does place a lot of pressure on us that was not originally envisaged
when the pipeline project was conceptualised a number of years ago.
While we are happy to compete commercially with any other fuel - it
is part of our role to do that - there is just a sense that these coal-fired
projects in Queensland are slipping in under the wire, so to speak,
before they can be judged by a new set of rules, because should a new
set of rules come in that will assess greenhouse emissions and factor
those costs in, we think that they would have a much tougher job in
justifying their position. From our point of view, there is almost like
an unseemly rush to get these things built. [22]
5.31 The impact of energy market reforms on the greenhouse emissions
from the sector has also been the subject of two reports commissioned
by the Commonwealth Government: an Allen Consulting study commissioned
by the Department of Industry Science and Resources, delivered in March
1999; and a McLennan Maganasik (MMA) study commissioned by the AGO, delivered
in June 2000. MMA also carried out modelling for the first Allens Report.
5.32 The Allen study echoed the analysis above, and added that:
- an excess of generation capacity over supply was acting as a barrier
to new entrants;
- transitional arrangements (such as `vesting' or fixed-price contracts)
favour incumbent generators;
- competitive pressures are increasing the reliance on existing, emissions-intensive
plant;
- current network pricing practices disadvantage cleaner fuels; and
- transmission pricing discriminates against cogeneration and embedded
(or `distributed') generation. [23]
5.33 Other witnesses also pointed out the historical legacy of tax biases
towards fossil fuels. The renewable energy expert Carrie Sonneborn told
the Committee:
There is also a need - and this came out of the World Bank, because
it is not just in Australia; it is happening in many other countries
- for a reduction or ceasing of subsidisation of power generation from
fossil fuels. Historically in Australia the fossil fuel industry has
received very generous subsidies. In fact, one study estimates about
$40 billion worth since World War II, which has obviously helped to
build up that industry and establish it over many years. Some of the
subsidies have actually discriminated in favour of fossil fuels and
against the distribution of renewable energy, for example, the cross-subsidisation
of rural electricity and more generous tax deductibility for grid connection
than for the purchase of remote area power systems. The current continuation
of the diesel rebate in remote areas is a major disincentive for remote
area power for renewables. Remote areas in Australia are the niche market
for renewable energy, and the diesel fuel rebate is directly undermining
that one key area. [24]
Oversupply of coal-fired generation
5.34 The 2000 MMA Report listed the current oversupply, which was unlikely
to be absorbed before 2005:
There is a large excess of generating capacity compared to demand in
NSW and to a lesser extent a surplus in Victoria. In Victoria, the 500
MW Newport power station has been closed for refurbishment due to an
uneconomic rate of utilisation, although it was brought back into service
in July 1999. In NSW two units at Liddell Power Station and the four
units at Munmorah have been mothballed in response to low pool prices
and low utilisation. Based on current predictions of demand growth,
it is unlikely that new base load plants will be required in NSW and
Victoria until after 2005. [25]
5.35 This assessment was echoed by the Industry Commission. The construction
of much of this excess capacity occurred during the 1980s in the eastern
states in anticipation of a surge in demand which did not materialise.
Allens estimated that there is 31.6 percent of plant in reserve in NSW.
[26] As a result, not only is gas finding it
difficult to compete on price terms with coal, but the excess capacity
means that new gas-fired capacity would be unable to compete with the
recommissioning of mothballed plant. Allens suggested that such plant
could also be recommissioned by incumbents to repel new entrants. [27]
5.36 The Industry Commission thought that electricity prices would fall
to around $25 MWh after the introduction of competition. However, a range
of factors combined to push prices much lower - to under $15 MWh in 1997,
and between $20-25 MWh currently. These, say Allens, were `well below
the entry price of gas or coal-fired thermal generation'. Despite much
higher prices being achieved during summer periods of very high demand
(`needle peaks'), Allens argues that oversupply has reduced the impact
this would have on base-load prices:
Even at high prices, there is insufficient energy sold into the needle
peaks at present to sustain all of the existing gas-fired peaking stations.
The refurbishment and delayed re-entry of the Newport station in Victoria
appears to reflect this situation. It appears likely that there is insufficient
demand at prices suitable to sustain new, reasonably large-scale gas-fired
stations in Victoria and NSW at present. [28]
5.37 The commissioning of the new coal-fired power stations in Queensland
will also delay the absorption of this oversupply - hence the concerns
of the gas industry about the viability of the PNG gas project and pipeline.
Over the next ten years approximately 2,280 MW of new coal-fired generation
will enter the NEM from Queensland, through investments at Callide C (840MW),
Millmerran (840MW), Redbank (150MW) and Tarong North (450MW). [29]
Fixed price contracts - The Aluminium Case
5.38 `Vesting contracts' have also been a factor in the low prices and
are acting as a barrier to new entrants. They were implemented by all
states with the aim of giving existing generators and retailers some certainty
on the price of a portion of energy. Vesting contracts are expected to
be wound back as electricity markets become fully contestable, by about
2001, but the AGO fears they could be replaced with bilateral contracts
which fix the price of large tranches of supply outside the NEM price
pool. Allens also argued that vesting contracts were a significant factor
in the dramatic price falls when competition was introduced:
Vesting contracts are likely to have had a profound impact because
the vested contract price was set at a rate that in hindsight was too
high - initial tranches were priced at $44.50/MWh in NSW. This is well
above generators' marginal costs and probably above average costs…
. Thus generators were able to bid low to capture market share at prices
close to or below short run marginal cost when market pressures intensified,
in the knowledge that a large portion of their dispatch would be topped
up through vesting contracts. [30]
5.39 Fixed price contracts that are set very low can also enhance price
pressures and may work as a disincentive to industries to reduce emissions.
Some of these contracts have been made with large individual electricity
consumers as investment incentives. Such contracts are held by a range
of industrial users, with one particular large energy-using sector being
aluminium. The Australia Institute told the Committee that:
The prices paid for electricity by aluminium smelters are set in long-term
contracts and are a closely kept secret. However, enough information
is available to make a good estimate of the extent of subsidies. The
general belief in the electricity industry is that smelters pay between
1.5 and 2.5 cents/kWh for delivered electricity compared to around 5-6
c/kWh paid by other large industrial users. The former Victorian Treasurer
revealed that other high-voltage customers were paying up to three times
the price paid by the two Victorian smelters. The Victorian Auditor-General
estimates that in 1997-98 the Victorian Treasury paid $180 million to
the State Electricity Commission to subsidise the cost of electricity
to the two smelters (Portland and Point Henry), indicating a subsidy
of 2 c/kWh. On the basis of all available evidence, the total subsidy
to aluminium smelters in Australia amounts to A$410 million per annum.
[31]
5.40 Aluminium smelting accounts for 14 per cent of all electricity consumed
in Australia and for 16 per cent of the greenhouse emissions from electricity.
The Australia Institute argued that the subsidisation of electricity prices
for smelters `provides a perverse incentive to consume electricity' and
that `Australia's greenhouse gas emissions are substantially higher than
they would be if smelters had to pay the market price'. [32]
5.41 The Australian Aluminium Council denied that its industry was substantially
subsidised:
The industry is not subsidised, as is sometimes wrongly claimed by
some commentators. We do not believe that that contention is sustainable
on the basis of objective analysis. Electricity prices, which are mentioned
in that context, very often are set by an intensive and competitive
process. [33]
5.42 While it declined to provide the Committee with the prices paid
by smelters, the Council rejected the claims of the Australia Institute:
I cannot put very specific alternative figures on the table because
electricity sold to aluminium smelters is the subject of commercial
long-term contracts… With no documented evidence, Australia Institute
infers that because Victorian smelters pay a low price for electricity,
all other smelters in Australia must receive a similar low price and
these low prices must be subsidies. I am not commenting on the Victorian
price, but certainly it would not be right to assume that price in one
state and one operation was the same price that applied to all operations.
For example, the Australia Institute report admits it has no evidence
at all of the subsidy to Comalco in relation to the Boyne Island smelter
but simply assumes there must be one because of the assumptions they
have made in Victoria. Similarly, they assume that there must be one
for Point Henry smelter in Victoria when really their thesis is based
on the Portland operation as they see it. They ignore the analysis of
the Industry Commission in their report in 1998 on the aluminium industry
that very specifically found no subsidy for the Tomago and Capra smelters
in New South Wales. [34]
5.43 The Council did intimate that smelters had been able to secure highly
competitive prices in relation to other users:
For the electricity market to be efficient and, thereby, generate the
greatest wealth for Australia, electricity prices must not be related
to cost of production - that is not the way business operates anywhere
now - but rather related to what the market will bear by competitive
market forces. Obviously, suppliers will differentiate in that environment
between the sorts of customers they have. They range from aluminium
smelters which sign 10- to 15-year contracts on a take or pay basis
and set up a base load take of electricity that is very advantageous
to managing your electricity supply. I do not think that has been taken
into account. [35]
5.44 The Aluminium Council said that its metals sector had reduced emissions
by 2.4 Mt CO2-e between 1990 and 1998 and that the Oceania region had
the most efficient energy usage per tonne of product. However, it also
said that, apart from using electricity efficiently, it had little influence
over emissions from electricity generation and strongly opposed mandatory
measures to cut emissions, even though it was unlikely that the energy
sector could otherwise achieve the reductions needed to meet Australia's
obligations under the Kyoto Protocol:
There also has to be time for the electricity sector to reduce its
greenhouse gas intensity. That is one of the key issues for us. We have
to buy electricity from the electricity sector. We consider it is obviously
a priority for that to happen, but it is going to take some time and
it cannot be done. We can make progress, but we believe we are not going
to reach the long-term targets by 2010. There is no point in damaging
a world competitive valuating industry like aluminium while that process
of reducing electricity intensity is going on. [36]
5.45 In view of their large volume of exports, the Committee sympathises
with the Council's concerns about remaining competitive with suppliers
from non-Annex I countries. The Committee also notes that the industry
is also a large employer and contributes to export earnings. However,
reducing the greenhouse intensity of supply - a goal the Council supports
- requires moving the bulk of electricity generation to lower emissions
fuel sources. Actions taken at the industry level will have little impact
if outweighed by increasing emissions intensity of generation in the NEM,
as has occurred in recent years.
5.46 It is unacceptable for an industry which is such a disproportionately
large energy user, with approximately 6 per cent of total national emissions,
to be quarantined from an abatement effort that should be spread equitably
across the community. In the Committee's view this emphasises the need
to develop a least cost approach to abatement that spreads costs efficiently
and equitably, while rewarding investment in emissions reduction.
Recommendation 25
The Committee recommends that the Commonwealth and the states and
territories seek greater transparency from large electricity consumers
about the prices they pay for electricity if those prices are fixed outside
the pool.
Recommendation 26
The Committee recommends that state and Commonwealth governments seek
to publicly disclose details of any arrangements under which public monies
are effectively subsidising large industrial users through the provision
of low electricity prices.
Privatisation
5.47 It was also put to the Committee that privatisation has been a factor
discriminating against investment in cleaner technologies. Dr Clive Hamilton
clearly believed privatisation was a factor in the increasing greenhouse
intensity of the NEM:
Because of the way the competitive electricity market is operated,
along with the process of privatisation of generation and distribution
assets, particularly in Victoria, what we have seen is coal-fired generation
engaging in an extraordinary price cutting war in order to try and win
market share. [37]
5.48 The Allens' Report cited the example of the brown coal-fired Hazelwood
power station in Victoria, which `was a plant that was nearing the end
of its operational life in public ownership but which private owners have
given a new lease of life and expanded capacity'. Allens argues that this
has increased the current oversupply in the NEM, and adds to a context
in which operators are being forced to `squeeze the best out of their
plant'. [38]
5.49 The Director of the NGO, Environment Victoria, Ms Esther Abram,
told the Committee that the privatisation of the State Electricity Commission
of Victoria was accompanied by the imposition of a price cap:
This means that electricity prices are kept low, and for electricity
retailers to increase their profits they have to sell more electricity.
This has led to retailers selling airconditioning systems, thereby promoting
the sale of goods that are high on consumption of electricity. [39]
5.50 The emissions implications of privatisation are of particular importance
when the prices paid for assets are very high. In Victoria for instance,
the electricity industry was sold at historically high prices, some $30
billon in total. Commentators have remarked that the $3.5 billion paid
by Hutchison Whampoa in the recent sale of South Australia's ETSA Utilities
(distribution) and ETSA Power (retail), which together form a large section
of the State's power business, were much lower than the prices paid in
Victoria for similar assets. [40]
5.51 With the bulk of Victorian capacity in brown coal generation and
buyers seeking to recover costs in a hyper-competitive market, it is easy
to see how privatisation there has worsened the greenhouse emissions outcomes
from market reform. It may also be arguable that privatisation misdirects
investment from new (potentially cleaner and more efficient) generation
capital into old.
Recommendation 27
The Committee recommends that the states ensure that any future privatisation
plans are the subject of full and open public debate and take account
of the potential greenhouse implications of the sales. Prices should reflect
a future market which is likely to be constrained by mandatory pressures
to reduce emissions.
Recommendation 28
The Committee recommends that a national strategy be developed to
reduce the emission intensity of, and constrain the growth in overall
emissions levels, from the electricity generation sector. Such a strategy
should include national emission intensity standards for electricity generators.
Recommendation 29
The Committee recommends that the states and territories agree to
set mandatory targets to progressively increase the total proportion of
electricity generated from efficient power plants and low greenhouse intensity
fuels.
The Assumptions Behind Reform
5.52 A number of witnesses commented that the electricity market reform
process was based on a narrow economic objective of reducing electricity
prices, and had thus failed to take account of the potential environmental
costs of reform. The National Competition Council (NCC), which is the
national advisory body on competition policy reform, told the Committee
that:
The objectives of the reform process that we are associated with in
the electricity and gas industries is utilising and harnessing the benefits
of competition where feasible in the supply of those sources of energy
to provide benefits to consumers. Those benefits are primarily in terms
of reduced prices and, yes, it is true that that can have some implications
for the consumption of those sources of energy. [41]
5.53 The Council told the Committee that there was no reference in its
energy reform charter to greenhouse and that their `roles are tightly
constrained and we are also constrained from conducting any work that
is not on our work program as agreed by all governments. So yes, we would
be constrained from conducting that work [relating to greenhouse]; it
would go beyond our current mandate'. [42]
5.54 The NCC has an ongoing role in energy market reform, as part of
the broader National Competition Policy (NCP) reform process, through
its assessment of `satisfactory progress against NCP obligations', which
must be achieved to release the payment of Commonwealth funds for the
implementation of NCP reforms. The NCC states that `where governments
don't invest in reforms in the public interest, reductions in NCP payments
may be recommended… The Council only recommends reductions in NCP
payments as a last resort where no path to dealing with outstanding issues
can be agreed'. [43]
5.55 The constraint on the Council's work in energy reform contrasted
with its work on water reform. Its Executive Director, Mr Ed Willett,
said that environmental considerations such as dryland salinity were a
part of its mandate in that area:
In water it is part of the competition policy reform agreements and
governments have recognised that water reform under NCP is not just
a matter of introducing competition and getting the benefits of competition.
It is really more about pricing efficiency. And it is when you start
getting into pricing efficiency issues that you start having to deal
with external costs like dry land salinity for example. Those sorts
of issues are not raised in the NCP agreements in relation to gas and
electricity. [44]
5.56 The Committee notes the inclusion of crucial environmental considerations
in water management and policy reform, and supports the inclusion of similar
environmental costs and considerations into the process of energy market
reform and the structure and operations of the national energy markets.
Recommendation 30
The Committee recommends that the Council of Australian Governments
designate the reduction of harm to the environment as a goal of ongoing
energy market reform, with a specific requirement for the reduction of
the greenhouse intensity of power generation.
Recommendation 31
The Committee recommends that the National Competition Council incorporate
benchmarks for the reduction of the greenhouse intensity of power generation
into its assessment of governments' progress on national competition policy
reforms.
Gas - A Transitional Fuel?
5.57 The Australian Gas Association, which commissioned a study on the
comparative emissions intensity of gas and coal, told the Committee that:
When it comes to power generation or applications such as producing
hot water or space heating for residential, commercial and industrial
purposes, the greenhouse gas emissions of natural gas are much lower
than those of black and brown coal. In fact, for power generation it
produces about half the emissions of brown coal, and emissions are 40
per cent lower than for black coal. In applications within the residential
sector for space heating and hot water systems, you are looking at about
20 per cent of the emissions of black and brown coal. [45]
5.58 The large gas producer, Woodside Energy, asserted that liquefied
natural gas (LNG) also has emission benefits if it displaced coal:
Studies by CSIRO and Energetics on behalf of the Australian Gas Association
have shown CO2 equivalent emission reductions of 40 to 50 per cent when
compared with coal. It is estimated that 20 million tonnes of carbon
dioxide equivalent emissions would be saved in Japan if the 7.5 million
tonnes of LNG from the LNG expansion project were substituted in that
country for coal. [46]
5.59 AGL claimed that if the PNG gas project and pipeline were to proceed
it would save 88 Mt CO2 within ten years:
An ACIL study that was commissioned to look at this factor found that
once the pipeline is in operation it will save 88 million tonnes of
CO2 in the first decade of its operation, with savings of about 11 million
tonnes a year by the year 2012. [47]
5.60 Woodside Energy asserted that `a key plank of Australia's greenhouse
policy must include measures to advantage penetration of natural gas into
key international and domestic markets'. [48]
They were echoed by the Australia Institute's Dr Clive Hamilton, who argued
for long term thinking towards achieving a transformation in Australia's
energy economy:
In Australia we will, over time, burn less coal in order to meet the
target in the first commitment period and much more stringent targets
in subsequent commitment periods. The issue is: what industries do we
develop and promote in order to substitute for the energy we currently
get from coal? I think it lies in managing that transition away from
coal. Coal is dead. It will take some decades but coal is going out.
There is no question about that. [49]
5.61 Dr Hamilton argued that gas would have an important role to play
in such a transition:
I think natural gas is the great winner out of the Kyoto Protocol…
natural gas is the transitional fuel for the next perhaps 20 years…
we should vigorously pursue both the substitution of natural gas for
coal, and we should also pursue renewables and energy efficiency, because
in 20 years or so, when we go into the second commitment period and
we have much tighter restrictions, even though gas has about half of
the emissions per unit of electricity delivered and even less for direct
consumption of gas in the homes and so on, it is a fossil fuel after
all and it does contribute to global warming. So we must prepare for
a world not only beyond coal but beyond fossil fuels. [50]
5.62 Pacific Power, which has investments in coal and renewables, acknowledged
the potential contribution of gas but were more sceptical of its value:
We do not think that gas is the answer… Even if [plants such as
our 400MW Wollongong proposal were] to proceed, gas effectively increases
emissions. It simply does that at a slower rate than would otherwise
be achieved. The only way it can actually cause lower emissions is if
it causes other plant to be displaced - in other words, it forces an
existing generator to exit the market. That seems extremely unlikely
in an industry that is characterised by high capital cost long life
assets.
The gas itself may not even be available, and there are statistics
there about that. But our view is that it could be more effective to
combine coal-fired generation - and I mean low emission coal generation
- with renewables to achieve a reduction, rather than to rely on gas.
That would not only achieve the same emissions result of the end of
the day but potentially allow the development of renewable industries
in Australia, which could very well be regionally based. [51]
5.63 Pacific Power argued that it is of long term importance to create
a market and regulatory climate conducive to the growth of renewables,
and that unless gas is able to displace coal generation, it merely reduces
the growth in emissions rather than achieving outright reductions. However,
with current rates of emissions growth, the Committee supports the use
of gas alongside policies to promote the uptake and development of renewables.
Cogeneration and Transmission Pricing
5.64 The Committee also heard that current energy market conditions and
rules unfairly disadvantaged lower emissions forms of generation such
as cogeneration and embedded generation.
5.65 Cogeneration is achieved through the harnessing of the energy produced
by other industrial processes such as sugar milling, chemicals, refining,
and pulp and paper, and in 1996-97 made up 4.5 per cent of Australia's
electricity generation. Embedded generation is defined in the National
Electricity Code (NEC) as that which is connected to an electricity distribution
network rather than a transmission network. They are generally located
close to their site of consumption and are often linked with industrial
processes. They range in size from very small to 250 MW, and can reduce
greenhouse emissions through reduced network transmission losses and because
embedded generators are often less emissions-intensive than other fossil
fuel sources such as coal. The extent of emissions savings depends on
the particular plant type, energy source, and location in relation to
the site of power consumption. [52]
5.66 According to the Australian EcoGeneration Association (AEA), cogeneration
can produce electricity at a much lower greenhouse intensity than conventional
fossil fuel generation:
Typically in gas-fired cogeneration using gas turbines you are still
burning a fossil fuel in the gas turbine creating emissions, but you
are creating emissions at one-third the amount of black coal and maybe
a quarter of the emissions of brown coal. [53]
5.67 Where cogeneration uses renewable sources such as biomass, the output
is treated as entirely renewable. Origin Energy, which operates Australia's
largest cogeneration facility at Osborne in South Australia, and a total
of 375 MW nationwide, claimed that:
Our eco-efficient plants deliver major reductions in greenhouse gas
emissions compared with the industry average - something around one
million tonnes a year less CO2 than the industry average. We have been
involved in developing and building three of the four gas-fired cogeneration
and power generation plants that have been built on the eastern seaboard
since the national electricity market commenced operation. Our cogeneration
projects are the heart and lungs for major investments by our industrial
customers, customers like BP in its $500 million Queensland clean fuels
project expansion which today is in the process of commissioning. [54]
5.68 The AEA told the Committee that, in 1998, there were some 130 cogeneration
projects in Australia, with a capacity of about 2,100 MWh and a production
of 9,500 GWh a year. By 2000, capacity had risen to 2203 MW and accounted
for 5.6 per cent of total generation. This compares poorly with international
trends, exceeding only Ireland, Greece, Japan, France and the UK, while
trailing the US (7 per cent), Germany (10 per cent), the Netherlands (40
per cent) and Denmark (50 per cent). [55]
5.69 They also said that while there was substantial scope for cogeneration
to be expanded, current market conditions had effectively stalled progress:
There is nearly 4,000 megawatts of cogeneration capacity that is under
development and evaluation. Our whole sector has been stalled over the
last few years, largely for two reasons: firstly, energy market reform
and some of the problems that we have in competing in the market; and,
secondly, the generally low level of electricity prices. In other words,
it is very hard to compete with $30 per megawatt hour coming from a
coal-fired generator. [56]
5.70 The AEA said no major cogeneration projects had been committed in
the eastern states over the past three years. However, they said that
if pool prices moved over $35 MWh, `you would see quite a lot of movement
in our sector. The difficulty is that coal is coming in at $30'. [57]
5.71 As a long term solution to these price imbalances the AEA recommended
the early trial of a domestic system of emissions trading. They recommended
that it be a `cap and trade' system with the majority of permits auctioned.
Revenues could then be returned to the economy in the form of reduced
business taxes on employment and investment. [58]
5.72 Another barrier to cogeneration, said the AEA, was the transmission
pricing arrangements in the NEC which unfairly advantage large scale generation
that is far from its site of consumption. They said that `we feel this
is probably the single most important barrier or issue that faces cogeneration':
[59]
Locational pricing and the incidence of transmission costs have a significant
impact on the development of new electricity generation capacity. Large
coal generators located distant from load centres have an unfair competitive
advantage as the costs of transporting their energy to market is paid
for by customers. [60]
5.73 Their concerns have been echoed by the Australian Competition and
Consumer Commission (ACCC):
The current proposal whereby the great proportion of network charges
will be levied on customers provides little incentive for the efficient
allocation of investment and generation options. As it competes on a
delivered cost basis, the incidence of network charges disadvantages
embedded generation options… the Commission is concerned that these
deficiencies in the Code may be contrary to the interests of embedded
generators and the wider Australian community. [61]
5.74 The AEA complained that these distortions were also a factor in
the viability of large new coal-fired power stations in Queensland at
the expense of less emissions-intensive forms of generation:
In the case of Callide C, Millmerran and Kogan Creek power stations,
they are the beneficiaries of significant new transmission investment
that has been undertaken by Powerlink, but will be paid for by customers
- not the beneficiary. This new coal-fired generation capacity is being
effectively subsidised at the expense of low emission cogeneration and
renewable generation. This is a perverse outcome that needs to be urgently
corrected. It has dire public policy consequences that will lead the
community to question the merits of micro-economic reform. [62]
5.75 The Commonwealth Government's submission to the National Electricity
Code Administrator (NECA) review of transmission pricing arrangements
supported this analysis:
Current arrangements, which restrict transmission charging to generators
to shallow entry costs, while leaving the bulk of costs to be recovered
from customers, provide a substantial subsidy to remote, usually coal-fired
generation to the competitive disadvantage of more greenhouse friendly
natural gas and renewable generation typically located closer to loads.
Pursuit of demand management options is also acutely disadvantaged.
[63]
5.76 These distortions were also discussed in the report by Allen Consulting
on the greenhouse implications of energy market reform. They argued that,
while these issues raise enormous technical complexities (for instance
truly cost-reflective pricing may require information currently beyond
technical capacities), it was accepted that the ways in which the NEC
deals with transmission pricing and embedded generation are problematic.
The ACCC has found that current transmission pricing practices are inefficient,
and the NECA has undertaken to involve the ACCC in an ongoing review of
transmission pricing arrangements. [64]
5.77 The AEA was very critical of NECA's efforts to date:
Unfortunately, the National Electricity Code Administrator that is
overseeing the review of transmission pricing has supported the incumbent
generators position - and has determined that existing generators should
not have to pay for the significant assets they use. This is notwithstanding
that nearly all other interested parties (including the Commonwealth)
argued the opposite. [65]
5.78 The removal of these distortions in transmission pricing is Commonwealth
Government policy. The NGS sets a timetable `to identify and address any
structural, legislative barriers to cogeneration' by June 2000, and to
establish `efficient and equitable locational signals, unbundling of transmission
charges, pass through of net benefit/cost embedded projects which deliver
network cost reductions/increases' by June 2001. [66]
5.79 The AGO's Philip Harrington stated that:
The National Electricity Code Administrator has conducted a review
of transmission and distribution pricing that sets out this issue. They
have made some recommendations as to how it could be addressed. I understand
those recommendations are with the ACCC for endorsement but I do not
believe the ACCC has handed down its decision at this time. [67]
5.80 NECA's recommendations to the ACCC fell short of the Commonwealth's
preferred changes. The Department of Industry, Science and Resources (DISR)
argued to NECA in 1999 that:
NECA's draft report offers no clear direction for future market development
and does not appear to have taken Government settings on competition
policy, and on energy and environmental policy into account. The current
draft seems premised more on maintaining the status quo, or at least
in arguing from the premise of existing market arrangements to substantiate
a change. [68]
Recommendation 32
The Committee recommends that the Government, the National Electricity
Code Administrator and the Australian Competition and Consumer Commission
work closely with the cogeneration industry to ensure that transmission
pricing regimes truly reflect the costs and distance of transmission and
contain no biases against embedded generation and cogeneration.
Footnotes
[1] Laurie Virr and Paul Hanley, Submission
199, p 1014.
[2] `The national inventory accounts for emissions
at the point of production, not consumption', Australian Greenhouse Office,
NGGI, Fact Sheet 2, July 2000, p 4.
[3] Australian Greenhouse Office, NGGI, Fact
Sheet 3, July 2000, p 1.
[4] Australian Greenhouse Office, National
Greenhouse Gas Inventory 1998, p A-3.
[5] Australian Greenhouse Office, NGGI, Fact
Sheet 2, July 2000, p 4.
[6] Australian Greenhouse Office, The National
Greenhouse Strategy: Strategic Framework for Advancing Australia's Greenhouse
Response, 1998, pp 98-99.
[7] Pacific Power, Submission 98, p 800; and
Dr Robert Lang, Proof Committee Hansard, 22 March 2000, p 351.
[8] Combined Explanatory Memorandum, Renewable
Energy (Electricity) Bill 2000/Renewable Energy (Electricity) (Charge)
Bill 2000, p 20; Mr Philip Harrington, Proof Committee Hansard,
Canberra, 22 June 2000, p 696.
[9] Allen Consulting and McLennan Magasanik
Associates, Energy Market Reform and Greenhouse Gas Emissions Reductions:
A Report to the Department of Industry, Science and Resources, March
1999, pp 8-9; and Ann Rann, Electricity Energy Restructuring: A Chronology,
Australian Parliamentary Library Background Paper 21, 1997-98.
[10] Allen Consulting and McLennan Magasanik
Associates, Energy Market Reform and Greenhouse Gas Emissions Reductions:
A Report to the Department of Industry, Science and Resources, March
1999, p 10.
[11] Ann Rann, Electricity Energy Restructuring:
A Chronology, Australian Parliamentary Library Background Paper 21,
1997-8, pp 23-26; and Mark Skulley, `SA sells power for $3.5 billion',
The Australian Financial Review, 13 December 1999.
[12] Ann Rann, Electricity Energy Restructuring:
A Chronology, Australian Parliamentary Library Background Paper 21,
1997-8, pp 9-11.
[13] Allen Consulting and McLennan Magasanik
Associates, Energy Market Reform and Greenhouse Gas Emissions Reductions:
A Report to the Department of Industry, Science and Resources, March
1999, p 11.
[14] Allen Consulting and McLennan Magasanik
Associates, Energy Market Reform and Greenhouse Gas Emissions Reductions:
A Report to the Department of Industry, Science and Resources, March
1999, pp 12-13.
[15] Dr Robert Lang, Proof Committee Hansard,
Sydney, 22 March 2000, p 351.
[16] Dr Harry Schaap, Proof Committee Hansard,
Sydney, 22 March 2000, p 335.
[17] Proof Committee Hansard, Canberra,
10 March 2000, p 60.
[18] Proof Committee Hansard, Canberra,
10 March 2000, p 60.
[19] Pacific Power, Submission 98, p 800.
[20] Pacific Power, Submission 98, p 804.
[21] Chevron Services Australia, Submission
123, p 1188.
[22] Mrs Leith Wood, Proof Committee Hansard,
Sydney, 23 March 2000, p 400.
[23] Allen Consulting and McLennan Magasanik
Associates, Energy Market Reform and Greenhouse Gas Emissions Reductions:
A Report to the Department of Industry, Science and Resources, March
1999, pp 24-49.
[24] Proof Committee Hansard, Perth,
17 April 2000, p 538.
[25] McLennan Maganasik Associates, Greenhouse
Gas Emission Projections: Australian Electricity Generation and Natural
Gas Combustion, Report to Australian Greenhouse Office, 5 June 2000,
p 16.
[26] Allen Consulting and McLennan Magasanik
Associates, Energy Market Reform and Greenhouse Gas Emissions Reductions:
A Report to the Department of Industry, Science and Resources, March
1999, pp 27-28.
[27] Allen Consulting and McLennan Magasanik
Associates, Energy Market Reform and Greenhouse Gas Emissions Reductions:
A Report to the Department of Industry, Science and Resources, March
1999, p 29.
[28] Allen Consulting and McLennan Magasanik
Associates, Energy Market Reform and Greenhouse Gas Emissions Reductions:
A Report to the Department of Industry, Science and Resources, March
1999, p 30.
[29] Australian EcoGeneration Association,
Submission 196, p 2069.
[30] Allen Consulting and McLennan Magasanik
Associates, Energy Market Reform and Greenhouse Gas Emissions Reductions:
A Report to the Department of Industry, Science and Resources, March
1999, p 30.
[31] The Australia Institute, Submission 79b,
p 595.
[32] The Australia Institute, Submission 79b,
pp 605-06, 610.
[33] Mr David Coutts, Proof Committee Hansard,
Canberra, 10 March 2000, p 45.
[34] Mr David Coutts, Proof Committee Hansard,
Canberra, 10 March 2000, p 48.
[35] Mr David Coutts, Proof Committee Hansard,
Canberra, 10 March 2000, p 48.
[36] Mr David Coutts, Proof Committee Hansard,
Canberra, 10 March 2000, p 46.
[37] Proof Committee Hansard, Canberra,
10 March 2000, p 60.
[38] Allen Consulting and McLennan Magasanik
Associates, Energy Market Reform and Greenhouse Gas Emissions Reductions:
A Report to the Department of Industry, Science and Resources, March
1999, p 32.
[39] Proof Committee Hansard, Melbourne,
20 March 2000, p 161.
[40] Mark Skulley, `SA sells power for $3.5
billion', The Australian Financial Review, 13 December 1999.
[41] Mr Ed Willett, Proof Committee Hansard,
Canberra, 23 June 2000, p 834.
[42] Mr Ed Willett, Proof Committee Hansard,
Canberra, 23 June 2000, p 833.
[43] National Competition Council, Submission
221, p 2851.
[44] Mr Ed Willett, Proof Committee Hansard,
Canberra, 23 June 2000, p 833.
[45] Mr William Nagle, Proof Committee Hansard,
Sydney, 23 March 2000, p 390.
[46] Proof Committee Hansard, Perth,
17 April 2000, p 485.
[47] Mrs Leith Wood, Proof Committee Hansard,
Sydney, 23 March 2000, p 390.
[48] Proof Committee Hansard, Perth,
17 April 2000, p 485.
[49] Dr Clive Hamilton, Proof Committee
Hansard, Canberra, 10 March 2000, pp 62-64.
[50] Dr Clive Hamilton, Proof Committee
Hansard, Canberra, 10 March 2000, p pp 62-64.
[51] Dr Robert Lang, Proof Committee Hansard,
Sydney, 22 March 2000, pp 350-51.
[52] Allen Consulting and McLennan Magasanik
Associates, Energy Market Reform and Greenhouse Gas Emissions Reductions:
A Report to the Department of Industry, Science and Resources, March
1999, p 43.
[53] Mr Ric Brazzale, Proof Committee Hansard,
Melbourne, 21 March 2000, p 219.
[54] Mr Andrew Stock, Proof Committee Hansard,
Brisbane, 26 May 2000, p 617.
[55] Mr Ric Brazzale, Proof Committee Hansard,
Melbourne, 21 March 2000, p 217; and Who's who in Australian Cogeneration
2000, Melbourne: Australian EcoGeneration Association, 2000, pp 14,
19.
[56] Mr Ric Brazzale, Proof Committee Hansard,
Melbourne, 21 March 2000, p 217.
[57] Australian EcoGeneration Association,
Submission 196, p 2069; and Mr Ric Brazzale, Proof Committee Hansard,
Melbourne, 21 March 2000, p 217.
[58] Australian EcoGeneration Association,
Submission 196, p 2061.
[59] Mr Ric Brazzale, Proof Committee Hansard,
Melbourne, 21 March 2000, p 222.
[60] Australian EcoGeneration Association,
Submission 196, p 2070.
[61] Australian EcoGeneration Association,
Submission 196, p 2070.
[62] Australian EcoGeneration Association,
Submission 196, p 2070.
[63] Australian EcoGeneration Association,
Submission 196, p 2070.
[64] Allen Consulting and McLennan Magasanik
Associates, Energy Market Reform and Greenhouse Gas Emissions Reductions:
A Report to the Department of Industry, Science and Resources, March
1999, p 39.
[65] Australian EcoGeneration Association,
Submission 196, p 2072.
[66] Australian Greenhouse Office, The National
Greenhouse Strategy: Strategic Framework for Advancing Australia's Greenhouse
Response, 1998, pp 42-43.
[67] Mr Philip Harrington, Proof Committee
Hansard, Canberra, 22 June 2000, p 690.
[68] Cited in Australian EcoGeneration Association,
Submission to the ACCC on NECA Network Pricing Code Changes, October
1999, p 5.
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