Mike Roarty
Science, Technology, Environment and Resources Group
December 1998
Contents
Major Issues
Introduction
Composition of Natural Gas
Energy Units used in the Natural Gas
industry
Inherent Advantages of Natural Gas
Industry Structure
Gas Transmission Pipeline Network
Proposed new pipelines and other
developments
Legislative Changes, Restructuring and Access
Arrangements
Impact of the Victorian Gas Crisis
Implications of the Victorian Crisis for Other
States
Supply
Reserves and Resources
Basin Developments
Pipeline Interlinkages
Demand
Prices
Liquefied Natural Gas
Conclusions
Endnotes
Appendix 1: Exponential units and conversion
factors
Appendix 2: Industry structure on a State-by-State
basis
Victoria
Production
Transmission, Distribution and Retailing
South Australia
Production
Transmission, Distribution and Retailing
New South Wales and the Australian Capital Territory
Queensland
Production
Transmission, Distribution and Retailing
Western Australia
Production
Transmission, Distribution and Retailing
Northern Territory
Production
Transmission, Distribution and Retailing
Glossary
Tables
Table 1: Natural gas use (PJ)
Table 2: Average natural gas prices 1992-93 to
1996-97 ($/Gigajoule)
Maps
Map 1: Australia's high pressure transmission
networks and sedimentary basins
Map 2: Potential gas sources for Eastern
Australia
Acronyms
|
AGA
|
Australian Gas Association
|
ACCC
|
Australian Competition and Consumer
Commission
|
BEAM
|
Boral Energy Asset Management
|
COAG
|
Council of Australian Governments
|
CNG
|
Compressed natural gas
|
GFCV
|
Gas and Fuel Corporation of Victoria
|
GJ
|
Gigajoule
|
IPART
|
Independent Pricing and Regulatory Tribunal (New
South Wales)
|
LNG
|
Liquefied natural gas
|
LPG
|
Liquefied petroleum gas
|
MJ
|
Megajoule
|
NWS
|
North West Shelf
|
ORG
|
Office of the Regulator General (Victoria)
|
PJ
|
Petajoule
|
PNG
|
Papua New Guinea
|
SAGASCO
|
South Australian Gas Company Ltd
|
SECWA
|
State Electricity Commission of Western
Australia
|
VENCorp
|
Victorian Energy Corporation
|
WAPET
|
West Australian Petroleum Exploration Pty
Ltd
|
The explosion in September 1998 at the Longford
plant in Victoria disrupted Victorian gas supply for almost two
weeks. The gas disruption had a major impact on Victorian industry
and the broader economy. Victorian industries which lost their
energy source were forced to close, and in addition, component
manufacturers and suppliers to Victorian industry in other States
also closed as there was no demand for their products during this
period. Businesses such as restaurants and hotels, along with
householders, lost their energy supply for water, space heating and
cooking. What became obvious following this incident was that the
State of Victoria had no alternative gas supply. The Victorian
Government along with business and the public have a heightened
sense of importance of energy security following this crisis, and
are likely to pursue options to improve security and alternative
supply options.
The Australian gas industry is being subjected
to major restructuring, somewhat akin to the Australian electricity
industry.(1) The restructuring has followed the findings of the
1990 Commonwealth's National Gas Strategy and the 1991 Industry
Commission Report on Energy Generation and Distribution. Both
highlighted the scope for reform of both gas and electricity
industries in order to increase competition and efficiency to lower
energy prices to both industry and domestic users. The
restructuring process to date has involved the breakup of a number
of government owned single entity organisations into competing
corporatised bodies, namely transmission, distribution or retailing
businesses. Significant progress has been made in respect to 'third
party access' legislation enabling independent operators to
negotiate on commercial terms to access transmission pipelines. The
supply of gas from the upstream sector comprising exploration for,
and development of, gas reserves is dominated by private sector
organisations. Many of these organisations control extensive
production and potential production areas and own vital gas
processing facilities. The marketing of gas including transmission,
distribution and retailing is a combination of both public and
private sector enterprises. The operations of transmission of gas
via high pressure pipelines and distribution via low pressure
reticulation systems within towns, cities and regional districts
are natural monopolies.
Many industry commentators have maintained that
the pace of restructuring has been slow. National access
legislation to gas pipelines, one of the primary initiatives in the
industry restructuring process which is not as yet finally
concluded, was originally envisaged as being completed by June
1996.
Restructuring in the upstream gas industry
sector has also been slow and implementing significant change
presents major challenges. Present operators are in many cases
joint venturers with title to large exploration tenements. They
also control and own the gas processing facilities. A case in point
is the Cooper Basin where a consortium dominated by Santos Ltd and
Delhi Petroleum has been producing natural gas and liquid petroleum
since the mid 1950s. Other examples include areas such as the
Gippsland Basin located offshore of the Victorian southeast
coastline. The challenge will be for third parties to obtain
acreage in these proven gas and petroleum provinces and
successfully develop competing supplies of both gas and petroleum.
Furthermore, following success with exploration and development of
gas and oil reserves, access to established processing facilities
will need to be obtained on fair and equitable commercial
terms.
With increasing competition in the upstream
sector of the gas industry, gas quality will become an increasingly
important consideration. Discoveries of gas deposits by newer
industry participants will likely be of a different nature and
composition (hydrocarbon and moisture content) to present
producers. For subsequent treatment and transportation of any new
gas, satisfactory third party access arrangements will need to be
negotiated.
Australia has abundant reserves and resources of
natural gas although they are unevenly distributed across the
country. The bulk of reserves are located offshore from
northwestern Western Australia (Carnarvon and Browse basins) well
removed from Australia's industrial and domestic markets. New South
Wales is presently the only mainland State that does not have its
own natural gas reserves. Australia has much more gas than it does
petroleum on which it is now partly import dependent. The largest
onshore accumulation of gas reserves is in the Cooper/Eromanga
basins in central Australia (see Map 1). It is this source that
supplies the gas markets in South Australia, New South Wales, the
Australian Capital Territory and Queensland. The offshore reserves
of the Gippsland Basin supply the Victorian markets and Victoria is
by far the largest gas user of any of the States. The reserves of
both the Cooper/Eromanga and Gippsland basins are considerable but
could be depleted substantially at present rates of consumption by
around 2020. At that stage, unless substantial new reserves are
found, gas will need to be transported either from Western
Australia, the Timor Sea or from Papua New Guinea (PNG) or a
combination of any of these (see Map 2).
Australia has an extensive network of pipelines
covering Australia (see Map 1) with three distinct interconnecting
networks:
-
- the eastern Australia network incorporating South Australia,
New South Wales, the Australian Capital Territory, Queensland and
Victoria
-
- the central network incorporating the Northern Territory
and
-
- the western network incorporating Western Australia.
These pipeline networks are not presently
linked. A number of new pipelines and extensions to existing
pipelines have recently been built and a number of major new
pipelines are planned. The Australian Gas Association states that
at present new pipeline proposals totalling some 11 000km in length
are at various stages of consideration. If all of these projects
proceeded, it would entail an investment of around $6 billion.
Consumption of natural gas in Australia has been
increasing since 1969 when gas was first transported by pipeline
from Roma to Brisbane in Queensland. Gas consumption in 1997 stood
at 817.8 (petajoules) PJ, with industry accounting for 355 PJ or 43
per cent of the total. Other major end use sectors include
electricity generation, minerals processing and mining, and the
residential and commercial sectors. Consumption of natural gas in
Australia is projected to increase around threefold by 2030. Gas
has environmental advantages in addition to a price advantage
relative to electricity, which will be an increasing driver for gas
industry expansions. The continuing pressure brought about by the
need to limit greenhouse gas emissions following the Kyoto and
Buenos Aries Conventions, favours the development of gas powered
power stations over coal fired power stations.
A consortium led by Woodside Petroleum Limited
has developed extensive gas and oil deposits on the North West
Shelf (NWS) and is Australia's single and major exporter of
liquefied natural gas (LNG). The project depends on continuing
growth markets in both Japan and other Asian countries, in
particular Korea. There are potential new markets in China. The
possible development of nuclear power plants in Japan is however a
negative for the expansion of the Australian LNG export
business.
The development of both liquefied petroleum gas
(LPG) and compressed natural gas (CNG) vehicles have been important
in the transportation sector. These vehicles have environmental
advantages in that they have considerably lower carbon dioxide
emissions (the principal greenhouse gas) and unlike diesel they
emit no particulate matter. The disadvantage is that there are far
fewer outlets for these fuels than for petrol and diesel,
especially in the case of CNG. Both these fuels are used
extensively in major cities, CNG is being used extensively in bus
fleets and LPG in taxi fleets. These fuels presently have a price
advantage because of their excise free status. This status of
course could be removed with a change in government policy. The
changing of the fuel taxing equations such as the present planned
reductions in the price of diesel fuel could impact negatively with
the further advancement of LPG and CNG vehicles.
The aim of this paper is to outline a number of
current issues pertaining to the Australian gas industry, provide
an insight into future developments and provide a broad overview of
the Australian gas industry as it currently stands.
The foremost issue in the natural gas industry
arises from the recent Victorian gas crisis. Because of the
proximity of large gas reserves located offshore in southeast
Victoria, in the Gippsland Basin, Victoria has used this gas as it
primary energy source since the 1970s. The disruption of essential
gas supply to Victorian industry, commercial businesses and
householders resulting from the Longford gas plant explosion
clearly indicated the vulnerability of single source supply with
little to no backup.
The Australian gas industry in 1998 is a mixture
of private and public sector entities and like a number of other
infrastructure industries is being subjected to major
restructuring. The overall objectives of restructuring are to
deliver both cheaper prices through increased competition and to
offer a wider choice of service. The restructuring process to date
has involved the breakup of a number of the government owned single
entity organisations into competing corporatised bodies and the
passing of 'third party access' legislation at Commonwealth and
State levels. The supply of gas from the upstream is dominated by
private sector bodies. The marketing of gas including transmission,
distribution and retailing is a combination of both public and
private sector enterprises.
Natural gas is becoming an increasingly
important energy source. In 1996-97 it contributed 17.7 per cent of
primary energy consumption in Australia and is projected to
increase that share to 28 per cent by 2030.(2) Natural gas has a
competitive edge over electricity in that it is around half the
price in terms of the delivery of an equivalent amount of energy.
Furthermore Australia has extensive reserves of gas which can be
used to Australia's competitive advantage.
Natural gas occurs in undergound reservoirs,
sometimes associated with oil, but often not. Oil exploration
efforts in Australia have yielded gas on a number of occasions with
little or no oil. Such deposits are called non-associated gas. The
exploitation of natural gas as an energy source is comparatively
recent except in the United States; vast quantities have been
'flared' as a waste product to facilitate crude oil production. As
recently as 1985 some nine per cent of international gas production
was treated in this fashion, the majority of this being in Nigeria,
Iran and Saudia Arabia.(3)
Unprocessed natural gas is composed of the
lighter hydrocarbon fractions, mainly methane (CH4) with
some ethane (C2H6). Depending on the source
of the gas it may contain minor amounts of propane
(C3H8), butane (C4H10)
and pentane (C5H12). Other constituents may
or may not be present, such as the longer chain hydrocarbons,
nitrogen (N2), carbon dioxide (CO2) and
hydrogen sulphide (H2S). Pure methane is colourless,
odourless and lighter than air. Impurities such as hydrogen
sulphide can give natural gas an odour. The composition of natural
gas used in Melbourne in 1996-97 was 91.2 per cent methane, 5.2 per
cent ethane, 0.6 per cent butane, 0.8 per cent nitrogen and 2.2 per
cent carbon dioxide.(4)
Ethane, propane, butane, and pentane are known
as natural gas liquids. Propane and propane/butane mixtures are
both known as liquid petroleum gas (LPG). The propane/butane
mixtures can vary up to around 50 per cent of each. Ethane is
widely used as a petrochemical feedstock. Where the natural gas is
low in these liquid hydrocarbons it is known as a 'dry' gas, in
contrast to what is known as 'wet' gas if the gas contains
quantities of both propane and butane. A 'sour' gas contains more
than one part per million hydrogen sulphide and is characterised by
a foul smell. Australian natural gas is generally 'sweet' due to a
low hydrogen sulphide content.
Gas measurement units are often extremely large
and it is customary for units to be prefixed with an exponential
factor. Commonly used exponential prefixes are outlined in Appendix
1.
Gas reserve and resource figures are quoted in
either cubic feet or cubic metres of gas and these figures can be
quoted in large numbers such as billions or trillions of cubic
feet.
The conversion factor for cubic metres to cubic
feet is outlined below:
one cubic metre (m3) = 35.315 cubic
feet (f3)
|
Following the conversion of cubic feet to cubic
metres, it is customary for the resultant figure firstly to be
converted to megajoules (MJ) and subsequently to petajoules (PJ).
Petajoules is a standard unit used in the natural gas industry.
From Appendix 1, one MJ = 106 joules and one PJ =
1015 joules. A joule is the basic unit of energy and
relates to a unit of work done. MJ can be converted to PJ by
dividing by a factor of 1x 109.
The conversion of cubic metres of gas to MJ
depends on the nature and composition of the gas, and varies
depending on where the gas is sourced. As New South Wales gas is
sourced from South Australia there is no separate figure for New
South Wales. The following factors apply to Australia's present gas
reserves and resources:
State
|
MJ per cubic metre
|
Western Australia
|
38.2
|
Victoria
|
38.6
|
South Australia
|
39.1
|
Queensland
|
39.6
|
Northern Territory
|
40.4
|
Production of liquefied natural gas (LNG) which
is produced on the North West Shelf of Western Australia is quoted
in tonnes. To convert tonnages to joules, the following factor is
used
one tonne LNG = 54.4 gigajoules (GJ).
|
The comparison of natural gas and electricity
costs in terms of equivalent units of delivered energy is outlined
in the Prices section.
Natural gas is a clean burning energy source
offering significant environmental and cost advantages over other
fossil fuels. Natural gas is viewed as an efficient,
environmentally friendly energy source that will play a major role
in future power generation and industrial development in Australia
and South East Asia.
Natural gas combines with oxygen on burning to
release heat, carbon dioxide and water, as with all other fossil
fuels such as coal, petrol and diesel. However, the burning of
natural gas releases by far the least amount of carbon dioxide of
equivalent energy released. Of the four common primary fossil fuel
energy sources, natural gas emits 55 kilograms of carbon dioxide
per gigajoule (GJ) of energy produced compared to 68, 91 and 95
kilograms of carbon dioxide for petroleum, black coal and brown
coal respectively. With ever increasing pressure to reduce or
contain greenhouse gas emissions (of which carbon dioxide is the
principal gas) following the Kyoto Protocol of the Framework
Convention on Climate Change agreed to in December 1997, natural
gas has significant comparative advantage for use in electrical
power generation. In addition, the burning of natural gas produces
little particulate matter and no fly ash as is produced with the
burning of coal. The burning of gas as opposed to the burning of
coal contributes significantly to the improvement of local air
quality.
Australia's LNG export industry replaces other
higher density fossil fuels like coal and oil that would otherwise
be used for power generation in countries like Japan. Although the
LNG production process adds to Australia's Greenhouse emissions,
the global environment is better off when Australian LNG is used in
preference to other fuels.
Although the use of liquefied natural gas and
compressed natural gas in the transportation sector is relatively
small at present, any increase in market share into this sector
would result in an improvement in present tail pipe emissions,
which cause major environmental problems, particularly in major
urban centres and cities.
The natural gas industry is widely dispersed
across Australia and gas is produced in all of the mainland States,
apart from New South Wales. Tasmania at present has no natural gas
industry. The major gas producing basins in Australia are offshore
northwest Western Australia (Carnarvon and Browse basins), offshore
southeast Victoria (Gippsland basin) and onshore central Australia
(Cooper/Eromanga basins) (see Map 1).
Australia's natural gas industry has five major
elements: production, transmission, distribution, retailing and
consumption. Production involves the exploration for and
development of gas reserves in Australia's various sedimentary
basins. Transmission involves the transportation of gas from the
well head or production area in high pressure large diameter
pipelines to decompression plants or city gate point prior to
distribution to customers (industrial, commercial and householder)
in low pressure small diameter distribution lines. Many of
Australia's transmission pipelines have compressor stations located
at regular intervals along the length of the pipeline in order to
boost pressure throughout the pipeline as required. Decompression
plants are usually located on the outskirts of major industrial or
residential areas.
Production, transmission, distribution and
retailing entities are generally either separately owned or
operated as 'ring-fenced' entities within a larger organisation.
Gas pipelines cross extensive parts of Australia with three
distinct interconnecting networks. New pipelines and extensions to
existing pipelines have recently been built which is gradually
extending the network. The construction of a number of additional
major pipelines is under consideration.
The industry structure is outlined in broad
terms on a State-by-State basis in Appendix 2.
Natural gas pipelines were introduced to the
United States in the 1920s, following the development of the oil
and gas industries, and became increasingly important as the use of
natural gas grew in the early post-World War Two era. However, they
did not appear in Australia until the late 1960s when Australia's
oil and gas industries were being developed.
The present transmission pipelines networks, consisting of
around 15 300km of high pressure pipelines is shown on Map 1.
The pipelines networks cross extensive parts of
Australia with three distinct interconnecting networks:
-
- eastern Australia incorporating South Australia, New South
Wales, the Australian Capital Territory, Queensland and
Victoria
-
- the central network incorporating the Northern Territory
and
-
- the western network incorporating Western Australia.
These pipeline networks are not presently
linked. New pipelines and extensions to existing pipelines have
been built relatively recently including the important linkage
connecting New South Wales and Victoria via the Wagga Wagga to
Wodonga pipeline. The Australian Gas Association maintains that at
present, new pipeline proposals totalling some 11 000km in length
are at various stages of consideration. These projects would entail
an estimated investment of around $6 billion. These proposals
include the Chevron and BHP Westcoast pipelines (see Proposed new
pipelines and other developments section below). New pipelines
serve both to extend the existing network as well as tap into new
gas resources, the Chevron pipeline proposal being a case in point.
The Westcoast proposal would also serve as a duplication of supply,
by more effectively linking the Cooper/Eromanga and Gippsland
Basins to supply both New South Wales and Victorian consumers. A
recent paper published by the Australian Gas Association(5)
outlines the main natural gas pipelines in Australia, detailing
year commissioned, length, capacity and ownership.

Source: Australian Gas Association
Major new proposals include the possible
building of two large pipeline transmission projects enabling gas
to be transported from PNG to Queensland and from the Gippsland
Basin in Victoria (Longford) to Wilton in New South Wales.
One proposal, the Chevron Gas Pipeline is to
bring gas from the Kutubu gas fields located in the central
highlands of Papua New Guinea across Torres Strait to North
Queensland and along the east coast to the Queensland industrial
areas of Townsville and Gladstone. The project participants in the
PNG Gas Pipeline Project are Chevron Asiatic Limited and BHP
Petroleum (PNG) Pty Ltd, together with a number of smaller
participants. The development of the Kutubu fields would have a
number of major benefits for both PNG and Queensland. PNG would
have a major resource development project from which it could earn
valuable export income and Queensland, and more particularly North
Queensland, would have access to gas reserves much closer than the
Cooper Basin sourced gas. Another major advantage is that this
pipeline would provide a second major alternative gas source for
Queensland as well as for other States, adding greatly to the
security of gas supply. Another proposal is the building of a
pipeline from Longford, Victoria to Wilton, New South Wales, which
would link supply from the Gippsland Basin to the Sydney market.
The project proponents of this East Australian Pipeline proposal
are BHP Petroleum and Westcoast Energy.
Another new development is the pending
relinquishment of oil and gas exploration tenements covering the
South Australian portion of the Cooper/Eromanga Basin by the South
Australian Government in early 1999. The South Australian
Government's aim is to markedly increase competition in the
upstream sector of exploration for, and development of, gas and oil
fields in the Cooper/Eromanga Basin. The expiry in February 1999 of
Petroleum Licences 5 and 6 covering 73 000 square kilometres,
including all of the South Australian Cooper Basin, will mark the
end of an important era in the history of petroleum exploration in
Australia. Since the first exploration licences were awarded in
1954, Santos Ltd and joint venture partners have drilled more than
1100 exploration and development wells and brought 119 oil and gas
fields on stream.
With the Cooper Basin now servicing the natural
gas needs of South Australia, New South Wales, the Australian
Capital Territory and southeast Queensland, the Basin now stands as
the hub of the major gas production, processing and transmission
system in Australia.
Legislative changes, restructuring and access
arrangements are important components of efforts directed towards
improving the operation and efficiency of the natural gas industry.
With the use of natural gas forecast to increase substantially in
the new millennium, structural changes to present industry
arrangements will enable increased competition and provide greater
security of supply of such an essential energy source.
The major aims of the restructuring process are
fourfold:
-
- To restructure the government owned gas businesses, leading to
a break up of single entity organisations into competing
corporatised bodies. The Victorian Government has expressed its
intention to privatise the State owned gas assets, as it has with
its electricity assets.
- To increase competition both in the upstream and downstream
sectors of the natural gas industry in order to have both competing
suppliers and retailers of natural gas.
- To introduce regulatory controls over the natural monopoly
components of the natural gas businesses such as the operation of
the transmission and distribution systems.
- To implement a 'third party' access and regulatory regime in
order that third parties that explore for and develop gas fields
can access existing processing facilities, together with pipeline
and distribution networks for agreed tariffs such that their gas
can be marketed.
The 'third party access' arrangements have
involved extensive Commonwealth and State legislative processes. In
1995, the Council of Australian Governments (COAG) established a
Gas Reform Taskforce to draw up a National Third Party Access
Code for Natural Gas Pipeline Systems (the National Access
Code). The aim was to establish a single set of rules for access to
all transmission and distribution pipelines and it is regarded as
the key element in achieving free and fair trade in natural gas.
This process was deemed necessary to encourage the development of a
nationally integrated and competitive natural gas market. Other
broader objectives were the removal of legislative and regulatory
barriers to trade, the commercialisation of remaining government
owned utilities, structural separation (or ring-fencing) of the
natural monopoly elements in the gas industry and reform of the
distribution franchise arrangements.
The National Access Code (approved by COAG on 7
November 1997 and known as the Code) will be given effect by
legislation (the Gas Pipelines Access Law) in each jurisdiction.
Legislation pertaining to pipeline access has been passed in a
number of jurisdictions including the Commonwealth (Gas
Pipelines Access (Commonwealth) Act 1998), South Australia,
New South Wales and the Northern Territory. Complementary
legislation in other jurisdictions is in process. The Australian
Competition and Consumer Commission (ACCC) will be the transmission
regulator once the relevant jurisdiction has proclaimed its
legislation and is hence covered by the Code. The ACCC will be the
relevant transmission regulator of 'covered' natural gas pipelines
in most Australian States (Western Australia is to set up its own
regulator). Many industry commentators have maintained that the
pace of restructuring has been slow. National access legislation to
gas pipelines, one of the primary initiatives in the industry
restructuring process, was originally envisaged as being completed
by June 1996.
The explosion at the Longford Esso/BHP gas
processing facility near Sale, Victoria in September 1998 severally
disrupted the entire Victorian gas supply. Gas supply was restored
on 5 October, in the first instance to industry and business
facilities and to domestic users in the following days. The gas
crisis followed an earlier problem in June also resulting in
disrupted gas production. This problem related to an ice blockage
at the Longford plant. The chronology of events of the major crisis
is as follows:
25 September: Explosion kills
two workers at the plant and injures seven, cutting gas supplies to
the State.
2 October: $100 million Federal
Government assistance package announced for Victorians affected by
gas shortages.
12 October: Victorian
government announces a Royal Commission into the two gas stoppage
incidents in order to determine the cause of the 25 September
explosion and the subsequent loss of supply.
The Royal Commission will examine a range of
contributing factors before making recommendations in February
1999. A former High Court judge, Sir Daryl Dawson, will conduct the
Royal Commission. The Commission will also examine risk management
and emergency procedures, any policy changes that have been made,
and any breaches by Esso/BHP of relevant statutes of regulations.
Recommendations by the Royal Commission may include proposed
changes to State laws or administration.
Only very small amounts of gas were available to
Victorians during the gas crisis. This supply came from the
recently completed pipeline link from Wagga Wagga to Wodonga
(bringing gas from the Cooper/Eromanga Basin via New South Wales),
and the gas supplied to the Warrnambool Portland region from the
small gas fields in the Otway Basin. Suffice to say that these
sources of gas supplied only minimal amounts of gas compared to
Victoria's total requirements. The Wagga Wagga to Wodonga linkage
effectively connects the supply basins of the Cooper/Eromanga in
South Australia to the Gippsland Basin in offshore Victoria
although the capacity of the pipeline is only small.
The gas disruption has had a major impact on
Victorian industry and the broader economy. A number of reports
have suggested the disruption has cost Victorian business about
$1.3 billion as well as the massive inconvenience to householders.
Victorian industries which had lost their energy source were forced
to close and in addition component manufacturers and suppliers to
Victorian industry in other States also had to close as there was
no demand for their products during this period. Businesses such as
restaurants and hotels along with householders lost their energy
supply for water, space heating and cooking.
What became obvious following this incident and
the subsequent loss of gas supply was that Victorians had only very
limited alternative supply. Supply up until the recent crisis has
been continuing uninterupted from the Esso/BHP joint venture for
almost thirty years. During the crisis, the gas reserves were still
in the gas fields and the gas distribution systems feeding gas
supply to industry and domestic users were still intact. However,
the gas processing plant at Longford, a vital link in the chain had
been severely damaged. To make matters worse, although only one of
three plants exploded (No. 1 plant), vital infrastructure necessary
for the operation of the two other plants (Nos. 2 and 3) was
damaged. Hence, it was not a matter of simply isolating the damaged
plant and continuing to operate the other two plants.
The Victorian Government along with business and
the public have a heightened sense of importance of energy security
following the crisis, and are likely to pursue options to improve
security and alternative options.
Esso/BHP first discovered oil and gas in the
Gippsland Basin in 1965 and have a virtual monopoly of supply from
this Basin. The Victorian Government is looking to develop other
supply options such as an expansion of the present New South Wales
gas linkage to enable increased flows of gas from this pipeline if
required. Furthermore, a connection with the Victorian southwestern
transmission network would allow gas to flow into the main
transmission networks from the Otway Basin. Gas supplied from the
Gippsland Basin could be stored in suitable sedimentary traps
(using reinjection technology) in the Otway Basin and drawn upon if
required. Another option that has been put forward by Epic Energy
is a plan to eventually continue the Moomba sourced gas from Murray
Bridge through Mount Gambier and into southwestern Victoria. This
would join the Mount Gambier linkages into southwestern
Melbourne.
The underlying rationale of the national
restructuring process currently underway is to provide both cheaper
gas prices together with alternative and competing sources of
supply. At this stage Australia is well behind the United States
and other European countries which presently have an interlocking
network of pipelines and multiple suppliers. However with
continuing progress with the restructuring process in Australia and
actions likely to follow in response to the Victorian crisis,
alternatives and options will be advanced at a quicker pace than
they may have been.
Could an explosion and fire similar to the one
that paralysed Victoria's gas supply happen in South Australia and
subsequently disrupt supplies from the Cooper/Eromanga Basin to
South Australia, Queensland, New South Wales and the Australian
Capital Territory? While nothing is impossible, the producing
companies maintain that in the event of a major mishap, supplies
would be maintained.
On the surface however, the systems seem
vulnerable. There is a one main supplier, and a single processing
plant.
The good news is that a number of commentators
say the circumstances are different from those in Victoria. The
pipelines from Moomba are long and have many days, if not weeks, of
supply in the pipelines themselves. If there was a problem at the
supply end, the gas contained in the pipeline would be sufficient
to continue supply with prudent supervision, whilst repairs were
made at the supply end of the chain. The long pipelines are termed
'line-pack' in that they are a source of gas storage in
themselves.
Some major facilities are also dual powered. The
Torrens Island (electrical power station) in South Australia, for
example, is gas fired but can switch over to fuel oil if
required.
Other States will be very mindful however of the
Victorian situation and would aim not to be dependent on a single
source monopoly supply. Plans such as the building of the Chevron
PNG pipeline bringing gas from PNG, reducing the dependence of
Queensland and, to some extent New South Wales and the Australian
Capital Territory on Cooper/Eromanga Basin gas will significantly
reduce supply vulnerability. In addition, the building of the
pipeline from Longford to Wilton (and connecting Gippsland Basin
gas to New South Wales and indirectly to Queensland and South
Australia) will add much needed security to these two States.
Reserves and Resources
Australia has large resources of natural gas. As
at the end of 1997 Australia's proven and probable reserves stood
at 92 800 petajoules (PJ) with potential additional resources of
29 700 PJ, enough to satisfy Australia's current consumption
and export markets for over one hundred years at current levels.
However, the gas reserves and resources are distributed unevenly
throughout Australia, with the bulk of reserves located offshore
from northwest Australia (Carnarvon and Browse Basins), well
removed from Australia's industrial and domestic markets. The
largest onshore accumulation of gas reserves and resources occur in
the Cooper/Eromanga basins (4425 PJ) in northeast South Australia
and southwest Queensland and it is this source that currently
supplies the largest domestic gas markets that are located in South
Australia, the Australian Capital Territory, New South Wales and
Queensland. Present initiatives, such as the release of tenement
areas and the further development of natural gas pipeline
infrastructure aimed at fostering further exploration for and
development of gas reserves, may result in additional gas
discoveries in South Australia. Considerable potential gas
resources exist in eastern Australia in the form of the little yet
utilised coal bed methane deposits in the Bowen and Sydney basins
in Queensland and New South Wales. Furthermore, the building of the
proposed PNG Chevron pipeline linking PNG to North Queensland
(which is much closer geographically that the Eromanga/Copper Basin
gas fields) and the industrial areas of Townsville and Gladstone
substantially strengthens Australia's access to gas reserves if
supplied at acceptable prices. The gas reserves in the central
highlands of PNG in excess of 9000 PJ outlined to date are of
similar magnitude to that contained in Australia's Gippsland
Basin.
Basin Developments
Exploration and development is being undertaken
in all gas producing basins in Australia. Presently the bulk of
proven reserves are located in the Carnarvon and Browse Basin in
offshore Western Australia. Other large gas accumulations that
occur away from large centres of population include the Kutubu gas
field in the central highlands of Papua New Guinea and the
Bonaparte Basin offshore from the Northern Territory.
Whilst there are opportunities for extending gas
reserves in eastern Australia, especially in the Cooper/Eromanga
Basin where increased competition will begin in earnest in early
1999, there will come a time early in the new millennium when gas
will need to be transported from west to east to satisfy
demand.
In a major study of gas supply and demand
undertaken by the Australian Gas Association(6), it was concluded
that eastern Australia will require additional supplies of gas
within the region (including increased production from existing
basins and coal seam methane) to meet projected forecast demand
between 2000 and 2008. Only preliminary work has been undertaken at
this stage to determine the size and extent of coal bed methane
deposits. Furthermore there will be a need for longer distance
supplies (outside the region) to meet forecast demand to 2030.
Options include offshore Western Australia, offshore Northern
Territory and Papua New Guinea. Broad directional arrows rather
than pipeline linkages are shown on Map 2 to illustrate this
notion.

Source: Modified from Australian Gas
Association
Consumption of natural gas in Australia has
increased by 16 per cent from 707 PJ in 1993 to 817.8 PJ in 1997.
Consumption of natural gas by market segment for the years 1993 to
1997 is shown below in Table 1.
Market segment
|
1993
|
1994
|
1995
|
1996
|
1997
|
Industrial
|
309.2
|
327.2
|
338.2
|
336.1
|
355.0
|
Commercial
|
39.6
|
40.1
|
43.3
|
45.7
|
46.5
|
Residential
|
97.8
|
96.2
|
104.7
|
111.3
|
112.8
|
Mining
|
103.1
|
105.4
|
117.3
|
130.4
|
133.1
|
Electricity generation
|
136.4
|
146.3
|
167.4
|
151.6
|
147.6
|
Transport
|
6.5
|
7.8
|
8.8
|
9.3
|
10.6
|
Other
|
14.4
|
13.8
|
13.4
|
12.7
|
12.0
|
Total
|
707.0
|
736.8
|
793.1
|
797.1
|
817.8
|
Source: The Australian Gas Association, Gas Statistics Australia
1998.
The industrial sector accounting for 355 PJ or
43 per cent of the total in 1997, was by far the largest end use
segment. Other major end use sectors include electricity
generation, mining and minerals processing, the residential sector
and the commercial sector. Consumption of natural gas in Australia
is projected to increase around threefold by 2030. The continuing
development and construction of pipelines and competitive marketing
both in the upstream and downstream gas sectors will provide the
necessary infrastructure and mechanisms for increased demand. It
can be convincingly argued that, in addition to the continuing
advantage in price that gas currently has in terms of comparable
energy delivered per unit of price in comparison to electricity,
gas also has environmental advantages. For example, gas has a clean
and environmentally friendly energy label in comparison with many
other energy sources and emits lower carbon dioxide per unit of
energy produced than all of the other fossil fuels. A major gas
market is developing with future electricity generating plants
being gas driven in preference to coal power.
It is clear from the figures above that the bulk
of gas usage is in industrial markets, largely for process heating,
followed by gas powered electricity generation, mining and minerals
processing and the residential sector. There has been growth in all
of these sectors over the years 1993 to 1997. According to the AGA,
there were almost three million gas customers in Australia in
1996-97, comprising 2.9 million residential customers, 80 621
commercial and 8812 industrial customers.
The AGA projects gas demand will continue to
grow through the years to 2029-30 and predicts gas usage to be
1495, 1642 and 2112 PJ in the years 2004-05, 2009-10 and 2029-30
respectively. Growth from 1996-97 to 2029-2030 is projected to be
258 per cent.
The above AGA study show that growth over this
lengthy time frame is expected to be strongest in the cogeneration
and gas powered electricity generation sector. Growth in this
sector is expected to increase by 363 per cent to 536 PJ by
2029-30.
Gas is a relatively cheap energy source and is
used industrially, commercially and by householders for a range of
uses including process heat, electricity generation, water and
space heating and cooking. Demand for natural gas is largely
dependent on population and industrial complexes and the major part
of demand comes from the eastern Australian seaboard.
Average natural gas prices for the years 1992-93 to 1996-97 are
shown in Table 2.
The prices for the three sectors, namely
industrial, commercial and residential show marked divergences with
industrial prices being less than half the price of residential
prices. Commercial prices are around 80 per cent of residential
prices.
Year
|
NSW
|
Vic
|
Qld
|
WA
|
SA
|
NT
|
ACT
|
Weighted average
|
Residential
|
|
|
|
|
|
|
|
|
1993
|
12.29
|
8.43
|
17.65
|
14.57
|
12.11
|
20.49
|
10.47
|
9.73
|
1994
|
12.51
|
9.06
|
17.52
|
14.65
|
12.44
|
na
|
10.31
|
10.21
|
1995
|
12.14
|
9.12
|
18.43
|
14.95
|
12.67
|
21.00
|
10.27
|
10.25
|
1996
|
12.91
|
9.15
|
18.6
|
14.96
|
13.37
|
19.5
|
10.82
|
10.16
|
1997
|
13.31
|
9.34
|
na
|
15.09
|
na
|
20.00
|
11.16
|
10.7
|
Commercial
|
|
|
|
|
|
|
|
|
1993
|
9.58
|
6.6
|
12.63
|
14.32
|
6.89
|
11.86
|
9.44
|
8.21
|
1994
|
9.30
|
6.42
|
12.56
|
15.02
|
6.82
|
12.30
|
9.23
|
8.06
|
1995
|
9.15
|
6.16
|
12.52
|
14.17
|
7.03
|
12.75
|
8.99
|
7.77
|
1996
|
9.10
|
6.32
|
12.67
|
15.07
|
8.77
|
12.86
|
9.17
|
7.65
|
1997
|
9.44
|
6.43
|
na
|
15.27
|
na
|
12.98
|
9.38
|
8.05
|
Industrial
|
|
|
|
|
|
|
|
|
1993
|
5.24
|
3.67
|
6.86
|
4.05
|
3.6
|
na
|
na
|
4.27
|
1994
|
5.21
|
3.75
|
7.11
|
3.71
|
3.57
|
na
|
7.73
|
4.16
|
1995
|
5.04
|
3.76
|
7.04
|
3.61
|
3.68
|
na
|
8.55
|
4.27
|
1996
|
5.13
|
3.71
|
7.22
|
np
|
3.74
|
na
|
8.17
|
4.43
|
1997
|
5.25
|
3.68
|
na
|
na
|
na
|
na
|
9.18
|
4.38
|
(a): Average prices are based on gross utility value divided by
volume of utility sales. They should not be interpreted as tariffs
or contract prices. Note: weighted average is calculated by use in
each State times price divided by number of States. 1992-93 = 1993,
na not available, np not published.
Source: Australian Gas Association, Gas
Statistics Australia 1998.
The above tabulation
shows little change in the average weighted annual prices for the
years 1992-93 through to 1996-97 for the commercial and industrial
sectors and a slight rise in the residential sector. There is a
marked variation in prices between the States with Victoria
exhibiting the cheapest prices for all classes of customers and
Northern Territory being the dearest.
Comparative analysis by the Australian Gas
Association (AGA) of gas and electricity prices for residential and
commercial customers, indicated that gas prices were around 2.5
times cheaper than for the equivalent electricity prices in terms
of per unit of delivered energy in 1996-97.
There are many claims and counter claims
regarding the cost competitiveness of competing energy sources and
it remains a continuing difficulty for all energy users
(industrial, commercial and householders) to accurately compare
costs of different energy sources. One of the main reasons for this
difficulty is the use of different energy units in the different
energy industries, namely the kilowatt hour (kWh) for electricity
and the megajoule (MJ) for gas.
For broad comparative purposes only,
household users in the Australian Capital Territory are
presently paying 1.0274 cents per MJ to AGL Retailing for gas in
comparison to paying 8.22 cents per kWh to ACTEW for
electricity.
Using a conversion factor of
natural gas is 2.2 times (8.22/1.0274 x 3.6)
cheaper than electricity for the delivery of an equivalent energy
unit in the Australian Capital Territory.
It must be noted that various tariffs are
available for different users. Industrial tariffs are considerably
lower than household tariffs. Also, many electricity users have
access to cheaper off-peak tariffs (for part of their total
electricity usage) that are considerably cheaper than the peak load
tariffs. As a general rule, industrial users of both gas and
electricity are charged considerably lower tariffs because of their
much higher usage.
The Liquefied Natural Gas (LNG) export industry
is of great importance to Australia. The development of the LNG
sector followed the development of the natural gas fields on the
North West Shelf (offshore northwestern Australia) for the Western
Australian market. The reserves of natural gas, discovered in the
early 1970s, were substantial and as such were found to be able to
support a sizeable export LNG business in addition to the supply of
natural gas to the West Australian market. The North West Shelf
project has been Australia's largest resources development
involving capital expenditure of around $12 billion to date. The
first phase of development involved construction of one of the
world's largest capacity offshore gas production platforms, North
Rankin A. The LNG development was undertaken by a consortium led by
Woodside Petroleum Ltd, the same consortium with some additional
participation as had developed the natural gas industry for the
domestic Western Australian market. Other project participants
include BHP Petroleum (North West Shelf) Pty Ltd, BP Developments
Australia Ltd, Chevron Asiatic Limited, LNG (MIMI) Pty Ltd and
Shell Development (Australia) Pty Ltd.
Australia's LNG industry began in 1989 when the
first cargoes of LNG were shipped from the North West Shelf to
Japan. Cooling natural gas in what is called a processing train to
minus 161 degrees celcius produces LNG. The gas is changed from the
gaseous state to liquified form and maintained at atmospheric
pressure at this temperature. The volume is reduced to one six
hundredth and is transported in purpose built ships. On arrival at
its destination, LNG is regasified in specifically built receiving
stations and made available for use in either power generating
plants or for distribution.
The LNG is presently a $1.5 to $2 billion a year
business. In 1985, and extending into the next four years, the
first two of an eventual three LNG processing trains, four LNG
storage tanks and a loading jetty were built. Following
commencement of LNG exports to Japan in 1989, construction of a
third LNG processing train was completed in 1992 and the project's
second offshore platform, Goodwyn A, commenced production in early
1995.
Australia's contribution to the world LNG trade,
through the North West Shelf gas project in Western Australia, is
currently around 7.5 million tonnes per annum and accounted for
around 11 per cent of the world trade and 14 per cent of the
regional trade in Asia in 1996. The North West Shelf joint venture
has 20 year contracts with eight Japanese utilities.
The joint venture is assessing the potential of
extending the term of existing LNG contracts beyond 2009 and of
expanding sales from as early as 2003, with the addition of the
construction of LNG trains 4 and 5. This project would involve
capital expenditure in the vicinity of $8.5 billion. Basic
engineering design is proceeding to schedule and once these two
larger trains with an additional 3.4 million tonne capacity are
operational, the total LNG capacity of the joint venture would be
increased to 14.3 million tonnes and export earnings could double
to just under $4 billion per annum. Recent market developments have
cast some doubt on the scheduling of this expansion and the joint
venture partners have conceded the dates may need to be pushed
forward.
A major LNG proposed development, the WAPET $9
billion Gorgon LNG venture will tap into gas fields that have been
discovered some 400km to the west of the present North West Shelf
fields. Production is unlikely to begin prior to 2004. One positive
recent development for this venture, together with further
proposals to establish LNG ventures in the Timor Sea, has been the
announcement of the Chinese Government's commitment to LNG as a
fuel source for Guangdong province in southern China. China has
flagged a demand of some 3 million tonnes of LNG per annum from
2004-05 and Australia is a preferred source. The Gorgon venture
however would require larger contract volumes than 3 million tonnes
to justify such a huge development.(7)
A further proposed LNG development is a 3.5
million tonne a year project in association with the committed
condensate and LPG project which is expected to start up by early
2002 based on the Undan-Bayu fields in the Timor Sea. Project
participants include BHP Petroleum and Phillips Petroleum of the
US.
At present Australia is one of only nine
countries that export LNG and there are only 10 importing
countries. However, several other countries are expected to enter
the industry either as producers or consumers or customers over the
next several years. Japan and Korea are the two largest importers
of LNG, accounting for 58 and 14 per cent respectively.
The Victorian gas crisis caused by a plant
explosion at Longford in September 1998 has had a major negative
impact on the Victorian economy and the broader economy as a whole.
Victorian industries which lost their energy source were forced to
close and component manufacturers in other States were also forced
to close as there was no demand for their products. The crisis
clearly demonstrated the vulnerability of a supply system of an
essential service with no alternative options. The Victorian
Government along with business and the public have a heightened
sense of the importance of energy security following this crisis,
and are likely to pursue options to improve security and
alternative supply options.
The Australian gas industry is being subjected
to major restructuring, somewhat akin to the Australian electricity
industry. The restructuring process to date has involved the
breakup of a number of the government owned single entity
organisations into competing corporatised bodies, namely
transmission, distribution or retailing businesses. Significant
progress has been made in respect to 'third party access'
legislation whereby independent operators negotiate on commercial
terms to access transmission pipelines. However, many industry
commentators have maintained that the pace of restructuring has
been slow. National access legislation to gas pipelines, one of the
primary initiatives in the industry restructuring process which is
not as yet finally concluded, was originally envisaged as being
completed by June 1996. Little progress has been made to date on
the issue of reform of the upstream sector although development in
South Australia relating to the relinquishment of long held
exploration tenements is a positive step.
Australia has abundant reserves and resources of
natural gas although they are unevenly distributed across the
country. The bulk of reserves are located offshore from
northwestern Western Australia (Carnarvon and Browse basins), well
removed from Australia's industrial and domestic markets. Australia
has much more gas than it does petroleum on which it is now partly
import dependent. The largest onshore accumulation of gas reserves
is in the Cooper/Eromanga basins in central Australia. The reserves
of both the Cooper/Eromanga and Gippsland basins are considerable
but could be depleted substantially at present rates of consumption
by around 2020. At that stage unless substantial new reserves are
found, gas will need to be transported either from Western
Australia, the Timor Sea or from Papua New Guinea (PNG) or a
combination of any of these (see Map 2).
Australia has an extensive network of pipelines
covering Australia (see Map 1) with three distinct interconnecting
networks:
-
- the eastern Australia network incorporating South Australia,
New South Wales, the Australian Capital Territory, Queensland and
Victoria
-
- the central network incorporating the Northern Territory,
and
-
- the western network incorporating Western Australia.
These pipeline networks are not presently
linked. A number of new pipelines and extensions to existing
pipelines have recently been built and a number of major new
pipelines are planned. The Australian Gas Association states that
at present new pipeline proposals totalling some 11 000km in length
are at various stages of consideration. If all of these projects
proceeded, it would entail an investment of around $6 billion.
Consumption of natural gas in Australia is
projected to increase around threefold by 2030. Gas has
environmental advantages in addition to a price advantage relative
to electricity, both of which will be increasing drivers for gas
industry expansions. The continuing pressure brought about by the
need to limit greenhouse gas emissions following the Kyoto and
Buenos Aries Conventions favours the development of gas powered
power stations over coal fired power stations.
The NWS is Australia's single and major exporter
of liquefied natural gas (LNG). The project depends on continuing
growth markets in both Japan and other Asian countries, in
particular Korea. There are potential new markets in China although
the possible development of nuclear power plants in Japan is a
negative for the expansion of the Australian LNG export
business.
Symbol
|
Prefix
|
Exponential
|
k
|
kilo
|
103
|
M
|
mega
|
106
|
G
|
giga
|
109
|
T
|
tera
|
1012
|
P
|
peta
|
1015
|
E
|
exa
|
1018
|
Victoria
The Esso/BHP joint venture found oil and natural
gas in the Gippsland Basin off the southeast coast of Victoria in
1965 and subsequently began producing natural gas for the Victorian
Government's Gas and Fuel Corporation of Victoria (GFCV) in 1969.
The joint venture has been supplying gas to the GFCV and more
recently to one of the corporatised components, VENCorp. The joint
venture has had a near monopoly of gas supply to Victoria since
1969 and up until the recent gas crisis, no major security issues
arose.
Production
The Esso/BHP joint venture produces over 98 per
cent of Victoria's gas. The rest comes from gas reserves in the
Otway Basin located offshore in Western Victoria, which supply gas
to Warrnambool and Portland. Esso/BHP also operate the major
processing plant at Longford near Sale in Victoria. This plant
processes all of the Gippsland Basin gas prior to transmission and
distribution. Cutlus Petroleum owns and operates a small on-shore
production facility at Port Campbell, which processes the gas from
the western Victorian Otway Basin field.
Transmission, Distribution and
Retailing
From 1 July 1997 the GFCV was broken up into a
number of components. These include a transmission operator,
Transmission Pipelines of Australia (TPA); three distributors
namely Westar, Stratus and Multinet; and three gas retailers namely
Kinetik Energy, Energy 21 and Ikon Energy. The distributors and
retailers presently have designated franchise areas. TPA has a
1600km network of transmission pipelines in Victoria. The provision
of overall regulatory control and management is provided by a new
created entity, namely the Victorian Energy Corporation
(VENCorp).
A new regulatory framework was recently
established in Victoria to give customers protection in terms of
price and service. The independent Office of the Regulator General
(ORG) will regulate service and pricing of the three gas
distributors and retailers while the Australian Consumer and
Competition Council (ACCC) will regulate gas transmission.
South Australia
The South Australian Gas Company Ltd (SAGASCO)
was established in 1861 and from 1863 began supplying what is
called town gas produced from the burning of black coal. Supply of
gas from the Cooper/Eromanga Basin began in 1969 following the
building of the Moomba to Adelaide pipeline by SAGASCO. Boral
Limited purchased SAGASCO from the South Australian Government in
1993.
Production
Gas from the Cooper Basin is produced by a joint
venture in which Santos Ltd is the operator and major partner in
the joint venture and the associated processing plant located at
Moomba. Gas from the Cooper/Eromanga Basin is supplied via pipeline
to South Australia, Queensland and New South Wales. Boral Energy
Resources operates the Katnook gas fields which supplies gas to
Mount Gambier and Katnook in the Otway Basin off the southeast
coast of South Australia.
Transmission, Distribution and
Retailing
South Australia is mainly supplied from gas
reserves in the Cooper/Eromanga Basin. Gas taken from the
Queensland portion of the basin is transmitted to Moomba by
pipeline owned by the South West Queensland (SWQ) Joint Venture and
operated by Santos. The pipeline from Moomba to Adelaide is owned
and operated by Epic Energy.
Natural gas is retailed in South Australia by
Boral Energy Limited and distributed by Envestra Ltd. Envestra was
formed in August 1997, when the natural gas distribution networks
of Boral, the Gas Corporation of Queensland (GCQ) and Centre Gas
Pty Ltd were combined into one organisation. Envestra owns and
operates around 8500km (around 6500km of pipelines in South
Australia) of natural gas distribution networks in South Australia,
Queensland and the Northern Territory supplying around 400 000
customers. Envestra has contracted Boral Energy Asset Management
Ltd (BEAM) to operate, maintain and expand its distribution
networks.
New South Wales and the Australian
Capital Territory
New South Wales is the only mainland State that
produces no natural gas. All gas used in New South Wales and the
Australian Capital Territory comes from the Cooper/Eromanga Basin
located in northeast South Australia and southwest Queensland from
a consortium dominated by Santos Ltd.
Gas consumed in New South Wales is transmitted
from the Cooper/Eromanga Basin by the Moomba/Sydney pipeline. The
pipeline is owned and operated by East Australia Pipeline Limited
(51 per cent owned by AGL in conjunction with TPA Victoria, 49 per
cent) and all distribution lines both within New South Wales and
the Australian Capital Territory are owned by AGL Limited.
Gas is marketed in New South Wales and the
Australian Capital Territory by AGL Retail Energy, a fully owned
subsidiary of AGL Limited. AGL Limited connected its 750 000th and
60 000th customers respectively in New South Wales and the
Australian Capital Territory during 1996-97.(8)
Queensland
Queensland is a State of Australian gas industry
firsts: Australia's first discovery of natural gas was in Roma,
Queensland in 1899. Australia's first commercial gas-fired power
station was located in Roma, in 1961. Queensland was the first
State to reticulate natural gas, which began when the pipeline from
Roma to Brisbane was officially opened in March 1969.
Production
Gas is supplied to Queensland from both the
Cooper/Eromanga Basin in South Australia and southwest Queensland
and the Bowen/Surat Basin in southeast Queensland.
In the Cooper/Eromanga Basin in southwest
Queensland, production licences are held mainly by Santos, Esso and
Boral Energy Resources, with Santos the dominant partner in the
joint venture and operator of the gas production and the Moomba
processing facilities for the joint venture. The joint venture also
treats gas imported at its Moomba plant from the Jackson field in
southwest Queensland en route to Adelaide and Sydney.
Queensland also has large reserves of coal seam
methane, that is methane gas encased in pockets and preferential
layers within the coal seams. The tapping and subsequent use of
coal seam methane has decided environmental benefits in addition to
the economics of using a product now largely wasted during coal
production. Methane is a particularly potent greenhouse gas and its
use is far preferential to its venting. Supplies of coal bed
methane are extensive and are yet to be fully evaluated. A 21km
pipeline from the Moura mine to the PG&E Queensland pipeline
was commissioned in December 1995 for the express purpose of
linking coal bed methane gas into the Queensland pipeline networks.
Coal bed seam methane was supplied for the first time in February
1996.
Transmission, Distribution and
Retailing
The Moomba (SA) to Ballera (Qld) pipeline is
operated by Santos Ltd. A 756km pipeline from Ballera to
Wallumbilla was completed by Epic Energy in late 1996, connecting
the Cooper/Eromanga Basin gas fields to Brisbane and a new pipeline
from Ballera to Mount Isa was completed by AGL Pipelines in 1998.
The Wallumbilla to Gladstone and Rockhampton pipeline is owned and
operated by PG&E Queensland Gas Pipeline. The PG&E
Queensland Pipeline also connects the Denison Trough (supplying
coal bed methane gas) in the Bowen Basin to Rockhampton and
Gladstone.
A central southern pipeline extending from
Gilmore to Barcaldine is owned and operated by Energy Equity
Ltd.
Natural gas is distributed in Queensland by both
Allgas Energy Ltd and Boral Energy Ltd, a wholly-owned subsidiary
of Boral Ltd. Allgas distributes to south Brisbane, the Gold Coast,
Toowoomba and Oakey, whilst Boral Energy distributes to north
Brisbane, Ipswich, Gladstone and Rockhampton.
Local Government authorities distribute gas in
Roma and Dalby. Natural gas is purchased from producers in the
Cooper/Eromanga basin and the Surat Basin.
Western Australia
In 1966 WAPET discovered gas in the Perth basin
and, following the building of the Dongarra to Perth pipeline,
began supplying gas to Perth in 1971. Since that time the massive
North West Shelf (NWS) oil and gas fields in the Carnarvon Basin
have been developed. Supply of natural gas to Perth from the NWS
Project began in 1984 and liquefied natural gas exports began in
1989. The NWS Project, incorporating a domestic gas supply plant
and a major natural gas liquefication and export facility has been
Australia's single largest resource development to date. The
project is operated by Woodside Petroleum Limited.
Production
The Carnarvon and Perth Basins provide most of
Western Australia's gas supply. In the Carnarvon Basin the Goodwyn
and North Rankin fields are operated by Woodside as part of the
North West Shelf (NWS) Gas Project. The project has two parts: the
domestic gas market and the LNG export market. The Carnarvon Basin
also contains the Tubridgi gas field which is operated by Boral
Energy Resources Ltd, the Harriet gas field which is operated by
Apache Oil Australia Pty Ltd and the Griffin field which is
operated by BHP.
Gas is also supplied to Perth from the Perth
Basin. The Woodada, Beharra Springs and Dongarra fields are located
onshore in the Perth Basin, between Perth and Geraldton. The
Woodada field is operated by Consolidated Gas. Beharra Springs is
operated by Boral Energy Resources. The Donagara licence is held
and operated by CMS Energy Corporation.
Transmission, Distribution and
Retailing
Western Australia is mainly supplied by gas from
the offshore fields in the Carnarvon Basin via the 1530km Dampier
to Perth pipeline and extending to Bunbury to the south of Perth.
This pipeline was purchased by Epic Energy from Alinta Gas in March
1998 for $2.4 billion. A pipeline also owned by Epic energy runs
further north from Dampier to Port Hedland where it supplies gas to
the Port Hedland power station.
Another major pipeline, some 1380km in length,
extends from Dampier on the northwest coast of Western Australia to
Kalgoorlie. This pipeline is owned by the Goldfields Gas
Transmission Joint Venture and was completed in 1996 and operated
is by AGL Pipelines (WA).
Gas is distributed to over 364 000 domestic,
commercial and industrial customers in Western Australia by the
state-owned corporation, AlintaGas, which began operation on 1
January 1995. Gas was previously distributed before that time by
Australia's only dual energy distributor, the State Energy
Commission of Western Australia (SECWA).
The 219km pipeline from Karratha to Port Hedland
was sold by Pilbara Energy Pty Ltd (a subsidiary of BHP) to Epic
Energy (Pilbara Pipeline) Pty Ltd in March 1998. Epic Energy plans
to construct a 24 km extension from the NWS facilities on the
Burrup Peninsula to the inlet for the Karratha to Port Hedland
pipeline, to enable natural gas to be supplied to the BHP hot
briquette iron plant.
Northern Territory
The Northern Territory's first gas discoveries
were made in the mid 1960s. The Mereenie field was the first of
these fields to be discovered (1964) followed by the discovery of
the Palm Valley field (1965). These fields are located 250 and
150km west of Alice Springs respectively.
Production
Natural gas in the Northern Territory is mainly
supplied from the Amadeus Basin located to the south of Alice
Springs. Gas is supplied to Alice Springs and Darwin via
transmission pipeline. Gas is supplied by a joint venture
comprising Magellan Petroleum Australia Ltd and Santos Ltd.
Production from the Palm Valley gas field to fuel the Alice Springs
power station began in 1983.
Ninety nine per cent of gas presently used in
the Northern Territory is for electricity generation, and 95 per
cent of electricity is generated using gas. The remainder is
reticulated by Centre Gas, a subsidiary of Boral Ltd, to commercial
and residential customers in Alice Springs and by NT Gas in
Darwin.
The Northern Territory also has extensive and as
yet undeveloped gas fields located offshore in the Bonaparte Basin
to the southwest of Darwin. The two major fields discovered to date
are the Petrel gas field discovered in 1969 and the Tern field
discovered in 1971.
Transmission, Distribution and
Retailing
NT Gas Pty Ltd, on behalf of the Amadeus Gas
Trust, operates the transmission pipeline some 1557km in length and
one of the longest in Australia carrying gas from the Amadeus gas
fields to Darwin. NT Gas is 96 per cent owned by AGL Ltd.
The 146 km pipeline from the Palm Valley gas
field to Alice Springs is also operated by NT Gas on behalf of
Holyman Limited.
In March 1996 natural gas was reticulated in
Darwin for the first time, when NT Gas began distribution to
customers in Darwin's Trade Development Zone.
In addition to gradually increasing demand in
the major population centres, projects such as the development of
the McArthur River Mine which uses gas to supply on site power
necessitated the building of a spur transmission line from Daly
Waters to McArthur River. The power station is operated by Energy
Developments Limited for the Northern Territory's Power and Water
Authority.
-
- Roarty, M.J., 'Electricity Industry Restructuring: The State of
Play', Research Paper No. 14, Parliamentary Research Service,
Parliament House, Canberra, 1997-98.
- Gas Supply and Demand Study, National Overview, Backgrounder,
The Australian Gas Association Canberra, 1997.
- Kay, P., 'Natural Gas - An Australian Growth Industry?',
Research Paper No. 2, Parliamentary Research Service,
Parliament House, Canberra, 1994, p. 5.
- Gas Facts 'Gas Fact Number 1', Australian Gas
Association, Canberra, 1998.
- The Australian Gas Association 1998, Gas Transmission
Pipelines: Development and Economics, AGA Research Paper No 8,
Canberra.
- Gas Supply and Demand Study, National Overview, Backgrounder,
The Australian Gas Association Canberra, 1997.
- Askew, K., 'Big gas projects still looking for customers',
Sydney Morning Herald, 13 November 1998, p 26.
- Annual Report 1997, Australian Gas light Company, p.
14.
augmentation
|
Additional capital works undertaken to increase
capacity.
|
cogeneration
|
The generation of electricity as a by-product of
another process in the industry. It involves the recovery of heat
or primary energy that would otherwise be wasted.
|
'covered' pipelines
|
Pipelined covered under the National Access
Code.
|
distribution
|
The process of transferring gas via low pressure
pipelines from the city gate to the consumer, whether it be
industrial, commercial or household.
|
downstream
|
The sector incorporating transmission,
distribution and retailing of natural gas.
|
joule
|
A basic unit of energy within the SI system and
used extensively in the natural gas industry. It is defined as the
energy conveyed by one watt of power for one second. For unit
multiples see Appendix 1.
|
linepack
|
Gas quantities contained within the
pipeline.
|
natural monopoly
|
Arises where the entire output of a market can
be supplied at a lower cost by one supplier than by any combination
of two or more firms. Reflects the presence of economies of scale
and or/scope.
|
processing train
|
Processing plant where natural gas is converted
to LNG.
|
ring-fencing
|
The internal separation of business functions
within an enterprise for management and accounting purposes.
|
reinjection
|
The process of pumping gas back underground into
either previously depleted gas fields or other porous sedimentary
layers.
|
transmission
|
The process of transferring gas via high
pressure pipelines from the processing facility located at or
adjacent to the gas fields to the city gate.
|
third party access
|
The process whereby a gas producer or purchaser
gains access to processing, transmission and distribution systems
on fair, reasonable and commercial terms in order to market
competing supplies of natural gas.
|
town gas
|
A manufactured gas produced from the burning of
coal.
|
upstream sector
|
The sector incorporating exploration for and
development of natural gas deposits.
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