AUSTRALIA'S GAS INDUSTRY GAINING NEW PROMINENCE

Australia's natural gas industry has undergone fundamental changes in the last few years.

A decade ago Australian gas discoveries were considered poor cousins to the more sought after oil finds. Few companies would have considered an exploration program targeting gas reserves. Now, although oil is still a major prize, the natural gas market in Australia is gradually assuming a much more prominent role in the country's energy mix.

The Australian Bureau of Agricultural and Resource Economics (Abare) predicts natural gas consumption in the country will grow at an average rate of 2.6%/year during 1991-2005. By then it will account for about 18.5% of Australia's total energy consumption.

Abare also projects that natural gas production from Australian fields will grow by an average 3.5%/year to 2005.

Although much of this growth is associated with liquefied natural gas, one of the nation's most rapidly expanding export commodities, there are likely to be some significant changes on the domestic scene that will contribute to increased use of gas during the coming decade.

AGA STUDY

A study by the Australian Gas Association (AGA) last year found Australia could require a major trunk pipeline linking large untapped gas reserves off Western Australia with major consumer markets on the country's eastern seaboard as early as 2009.

In addition, other interstate gas pipeline connections are likely to be needed by 2030. Of special note is a probable pipeline to link Northern Territory with southern and eastern states.

AGA's study found Australia has enough gas reserves to meet domestic demand for the next 30 years in addition to servicing existing gas export contracts. It estimates current proved and probable gas reserves at 105.45 tcf, excluding coalbed methane reserves found mainly in New South Wales and Queensland.

Australian gas consumption in 1991 totaled about 630 bcf. Demand is projected to jump to about 1.52 tcf by 2030 under a base case that calls for growth of 2.3%/year.

Under a high demand case of 2.9%/year, Australian gas consumption could reach almost 2 tcf by 2030.

The study also found that if state and territorial governments persist with their current reluctance to remove interstate gas trade barriers, there will be a sharp jump in gas prices compared with a scenario that eliminates interstate gas trade barriers.

By 2030, gas prices in Sydney could be 32% higher than in an unrestricted market. In Melbourne, gas prices would be 24% higher, and in Brisbane and Adelaide 31% higher.

By far the biggest growth engine in Australian gas demand will be the electrical power generation market. Under a base case, that sector is expected to consume as much as 408.5 bcf/year in the long term. Consumption for power generation could reach 693.5 bcf/year under the high case. That compares with current gas consumption of 95 bcf/ year for electrical power generation.

INTERSTATE GAS TRADE

Talk of change centers on the federal government's initiative, backed by the AGA, to create free trade of gas across state boundaries.

With one exception, the country's domestic gas industry has evolved as a series of separate entities, wherein a field's production is consumed only in the borders of the state in which the field lies. The exception is the supply of Cooper basin gas from South Australia under contract to Australian Capital Territory/New South Wales, where it is sold to Canberra, Sydney, Newcastle, and Wollongong markets.

The federal government's plan to put gas trade on a national basis is by no means a sure thing. There is considerable resistance to free trade from the government of South Australia in particular, which wants to ensure that its consumers have security of supply beyond the first few years of the next century, when existing contracts expire.

However, many observers believe increased cross border gas trade is inevitable and will be a feature of the domestic gas scene after 2000.

The seeds of change have been sown by a new 190 km gas pipeline linking fields in Southwest Queensland to the Moomba treatment plant in northeastern South Australia. This project began when the Queensland government authorized sale of 285 bcf of gas from four previously undeveloped Queensland Cooper/Eromanga basin fields to South Australia. Contracts were wrapped in April 1992. Producers, led by Santos Ltd., expect first gas to flow to Moomba in January 1994.

The deal has mutual benefits for both states. South Australia gets a much needed boost to security of future gas supply, while Queensland gains royalties on production along with the condensate associated with gas flow. Condensate will be fed into the existing oil pipeline connecting Southwest Queensland with refineries in Brisbane on Australia's eastern coast.

The result of the growth in gas pipeline infrastructure and in the increasing number and spread of end uses is that Australia's petroleum explorationists no longer view discovery of natural gas as little better than a dry hole, an attitude often adopted in the past. In some cases in recent times, there has even been an intent to explore for gas.

Notably this has occurred in the Cooper basin of South Australia, where there is a continuing need to keep at least a 5 year buffer of proved reserves ahead of consumption. It also has occurred recently in the Surat and Bowen basins of Southeast Queensland, where reserves depletion, has been outpacing additions from discoveries and extensions.

A similar intent may occur in the future in Bass Strait or the Otway basin-particularly if contracts are secured to supply gas across state boundaries, as advocated by the federal government.

PIPELINE PROSPECTS

Windows of opportunity for several more cross border gas pipeline projects are coming into view. Preliminary negotiations are under way for planning and construction for projects that have lead times of as much as 10 years.

One such project is the possibility of supplying the New South Wales market with gas from Bass Strait fields off Victoria once the current contracts for supplies from South Australian Cooper basin fields begin to expire in 2001. That would involve construction of a new gas pipeline across Victoria to link with the existing trunk line into the Sydney Canberra markets.

The rationale for this move is that South Australia has only 10 years of confirmed gas supplies, while Victoria has enough reserves in Bass Strait to supply its own consumer needs as well as those in New South Wales well into the next century. Bass Strait producers Esso Australia Resources Ltd. and BHP Petroleum Pty. Ltd. are anxious to capture at least part of the new South Wales market. The Sydney gas utility Australian Gas Light Co. is believed to be receptive to preliminary overtures.

Victorian producers also have eyes on the South Australian market, a prospect that has become much more plausible following BHP's recent discovery of Minerva gas field in the Otway basin about 10 km off southwestern Victoria.

In addition, South Australian markets are being wooed by producers in the South Northern Territory fields of Palm Valley and Mereenie. The proposal involves laying a pipeline direct from Palm Valley to Port Augusta at the head of Spencer Gulf in South Australia or to Moomba to link with existing lines to Adelaide and Sydney.

And waiting in the wings is the long running proposal to ship gas by pipeline from Northwest Western Australia across the continent to markets on the eastern seaboard.

However, it is unlikely this option will be economically viable until it is clear that the known or possible reserves in the central and eastern Australian hydrocarbon provinces are near depletion.

INTRASTATE PROPOSALS

Another feature of the changing gas scene in Australia is the move to expand pipeline networks within state boundaries.

A good example is the current proposal to move gas by pipeline from Northwest Shelf fields to the gold and nickel fields region centered around Kalgoorlie and Kambalda in South Central Western Australia.

The scheme was originally put forward by a coalition of Western Australian state conservative parties just before an election early this year, and it has been confirmed since conservatives won control of the state government in February.

What's more, the proposal has been enthusiastically embraced by private enterprise in Western Australia. As many as 16 groups have lodged expressions of interest, including a joint venture of Western Australia's three largest mining companies.

Considered to be the front-runner, the venture of Western Mining Corp., BHP Minerals, and Normandy/Poseidon has proposed a $400 million (Australian) project to lay and operate the gas line. The three are the main energy users along the proposed pipeline route and would take up as much as 90% of the initial throughput.

The proposal entails a pipeline designed to transport about 95 MMcfd of gas, which equals about 25% of the contract commitment for the domestic gas phase of the Northwest Shelf gas project. The venture estimates gas could be on stream 3 years after government approvals are given.

Although not as advanced, there are similar sized pipeline proposals in other states. Notably these include an extension of the Palm Valley/Mereenie-Darwin gas line to include a spur connecting with the Nabalco aluminum refinery at Gove on the northeast tip of Arnhem Land in Northern Territory. Such a line also would extend beyond the proposed new lead/zinc mine at McArthur River near the border with Queensland. Currently the Gove plant is powered by fuel oil brought in by sea from Singapore, but a change to natural gas fuel is under consideration.

Another possibility is a major trunk line feeding Southwest Queensland gas to that state's existing eastern sector pipeline network via Roma, thus linking with Brisbane and the central coastal cities of Gladstone and Rockhampton.

There also is potential for a line running north from Southwest Queensland fields to the Mount Isa copper/lead/zinc mining province.

FIELD ECONOMICS IMPROVE

The growing number of pipeline has led to another aspect of changed attitudes toward the use of domestic gas in recent years.

With the expanded infrastructure, producers are finding that even relatively small gas reservoirs can be viable for development. That applies to fields such as Tubridgi near Onslow on the Western Australia coast, which has proved and probable gas reserves of 85 bcf, and to associated gas in offshore Griffin oil field.

In both cases the gas is economic because it can be connected at relatively small cost to the major Northwest Shelf domestic gas line that extends along the Western Australia coast to Perth and markets in the southwest corner of the state. In addition, new markets are being proposed in the form of gas fired power plants at various mining centers in the northwestern mining belt.

Another interesting proposal being looked at along these lines is the possibility of connecting gas reserves recently found in the Point Torment field in the Kimberley region of Western Australia to the towns of Derby and Broome on the far northwest coast. The proposal still is in its infancy, and further appraisal of the discovery is needed, but the fact that it is being considered at all underscores a marked change in attitude toward the value of small to medium sized gas discoveries for local consumption.

Another example is the use of Palm Valley gas to produce a small volume of LNG in a plant at Alice Springs that is then trucked to the Ayers Rock complex 300 km away and used as fuel for power generation. And there is a new scheme that will involve piping gas from Gilmore field in central Queensland about 90 km to the town of Blackall, where it will be used to generate electricity for the region.

DOMESTIC CONSUMPTION

The industrial sector is the largest domestic market for gas in Australia.

According to a gas supply/demand study released late last year this sector accounted for about 351.5 bcf/year in 1990-91, or 48% of total consumption. Uses in industry include steam raising, drying, process heating, kiln firing, and feedstock and fuel in production of petrochemicals.

One noteworthy new development in the sector is the green light BHP gave to construction of a $70 million methanol pilot plant just west of Melbourne in Victoria. It will use Bass Strait gas as feedstock in a demonstration of new methanol technology developed by U.K. company ICI Katalco.

Sponsors hope the plant's innovative natural gas conversion technique will contribute to development of a significant share of Australia's uncommitted gas reserves and perhaps lead to applications on floating production, storage, and offloading facilities.

Although the plant's primary emphasis will be on technology development, its production of about 160 metric tons/day of methanol will supply most of Victoria's requirements, which are currently imported from abroad. The plant is to go on stream in second half 1994.

Natural gas consumption for power generation in Australia stood at 95 bcf/year in 1990-91, accounting for about 15% of gas used in the country. South Australia, Victoria, and Western Australia are the largest users of gas for this purpose. Power generation in the Northern Territory also uses gas almost exclusively as its fuel.

With more than 2 million customers, the residential sector accounts for about 85 bcf/year, or about 13%, of Australia's gas consumption. Commercial demand stood at 32.3 bcf/year in 1990-91, or 5% of gas use.

The sector with perhaps the best prospect for growth is transportation. Currently, the volume of natural gas-as opposed to liquefied petroleum gas-used in transport is only about 190 MMcf/year, but it is expected to rise to 28.5 bcf/year by 2005, if the gas industry's aim of achieving a 10% penetration of Australia's road transportation fleet within 10 years is successful.

Vehicle consumption of natural gas is taking two forms: development of trucks capable of running on LNG, and manufacture of fleet vehicles-particularly city buses and taxis-capable of running on compressed natural gas. Proponents of those vehicles claim significant fuel cost savings as well as extended engine life.

EXPORT GAS

Despite renewed interest in the domestic scene, the main potential for Australia's natural gas reserves lies in exports.

Notwithstanding BHP's hopes for methanol production, the export of LNG offers the Australian gas industry its largest potential increase in dollar terms.

Abare points out that LNG shipments to Japan from the Northwest Shelf project began at 2 million tons/year in 1989-90 and reached the 5.4 million ton/year mark early in 1993 on their way to a contract volume of 7 million tons/year by 1995. Abare says LNG exports will plateau at this level until 2000, when a new phase of growth is expected to begin. Shipments are expected to reach 9.3 million tons/year by 2002-03.

In terms of export earnings, Abare projects an increase from $1.15 billion in 1992-93 to $2.32 billion in 2004-05 in 1992-93 dollars.

The question that remains is to determine which projects have the best prospects beyond the current Northwest Shelf contract configuration.

Most of the current candidates have been defined for a number of years.

NORTHWEST SHELF UPDATE

The most obvious candidate for further action is an extension of the Woodside Petroleum Ltd. group's fields and facilities.

Although gas reserves in North Rankin and Goodwyn fields are fully committed to current contracts, there is potential for additions using gas from nearby Angel field. This is a reservoir discovered in 1972 and kept as a backup to safeguard existing commitments to Japanese customers.

But the Woodside group has wider ambitions. Discoveries within the company's license area the past decade include Echo, Yodel, Wilcox, and Dixon fields. There also are plans to consolidate the reserves picture with a new drilling program beginning this year.

Guided by results of an extensive 3D seismic survey completed in 1992, the first well will be an appraisal of the Dixon discovery. The focus then will shift to a number of other prospects in the area, the two fold aim being to prove enough gas reserves to sustain new LNG contracts and add to oil reserves expected to go on stream from Wanaea and Cossack fields in the mid-1990s.

GORGON/WEST TRYAL

Rivaling the Woodside group's plans are those of West Australian Petroleum Pty. Ltd. (Wapet), Perth, which has an estimated 8 tcf of gas and 40 million bbl of condensate in Gorgon and West Tryal Rocks fields west of Barrow Island and south of the Woodside operations.

The fields were discovered in 1980 and 1972, respectively, but they have remained in the shadow of the Woodside Northwest Shelf project mainly for lack of a gas market.

During the last few years Wapet has taken a number of steps toward an LNG project. These include an extensive 3D survey over Gorgon and feasibility studies on development technology as well as market surveys, particularly of the Asian region.

Development options being considered include building facilities next to the Woodside group's gas liquefaction plant on the Burrup Peninsula and building a grassroots plant on Barrow Island next to Wapet's oil facilities.

Decisions are expected this year on an appraisal drilling program in Gorgon, larger of the two discoveries. The most optimistic timing for any development project is the late 1990s.

A new gas strike, East Spar, has been made close to Gorgon/West Tryal Rocks by Western Mining Corp. Although more appraisal is needed, first indications are of a substantial discovery that may enhance prospects for a regional development project based on LNG exports early next century.

BONAPARTE GULF, BROWSE BASIN

Australia's only other potential medium term LNG development prospect lies in the Bonaparte Gulf and embraces the Petrel and Tern fields, found in the late 1960s and early 1970s.

For many years various appraisal programs were operated by Ste. Nationale Elf Aquitaine, but Elf withdrew in the late 1980s, and operatorship is now in the hands of Santos.

Lying 250 km west of Darwin, Petrel has four wells. Tern, 50 km farther west, has only two wells. Estimated combined gas reserves total about 3 tcf, but the reservoirs appear to be complex, and more appraisal work is planned.

Santos and Sumitomo Corp. are conducting feasibility studies for production of 2 million tons/year of LNG.

However, it may be found more economical to use gas from Tern and Petrel fields to supply gas to Darwin, with additional gas used for industry in Northern Territory. Another alternative is to reverse flow of the Palm Valley-Darwin pipeline and lay spurs to Moomba to allow supplies to reach Southeast Australian markets,

A wild card in the LNG stakes is combined development of the Woodside group's huge Scott Reef and Brecknock gas/condensate fields in the Browse basin about 350 km west of Broome on the northwest coast. They hold an estimated combined total of 17 tcf of gas and 200 million bbl of condensate.

However, the distance from land and lack of markets mean they are unlikely to see development until well into the next century.

FUTURE MARKETS

Australia sees its future LNG market opportunities mainly in Japan, South Korea, and Taiwan.

In 1991 those three countries imported a total of 40 million tons of LNG. This figure could double by 2005 if optimistic assessments of growth potential are correct.

Recent estimates show there will be a shortfall between contract supplies and market demand in those countries of 5-10 million tons by 2000. By 2005 that supply shortfall could rise to 13-24 million tons (OGJ, June 28, p. 23) .

Those are the windows of opportunity sought by Australian producers. There is no doubt gas reserves are available, and the country presents a politically stable and technically sound base from which to conduct a strong marketing campaign.

As with the domestic scene, successful market penetration will depend heavily on innovation and a selling price competitive with that of rivals, as well as with alternative energy sources.