Tax reform could double Western Australian industry

Opportunities in Australia/Current projects - Capex Forecast - 8 years [26,716 bytes] Offshore Production Table [38,317 bytes] In order for Western Australia to compete globally for participation in the country's oil and gas industry, reform of the tax structure will be necessary. Keith Hunter, Group General Manager for Operations and Technology for BHP Petroleum issued the request at the Offshore Western Australia Conference in Perth.

BHP manager cites high cost areas needing relief

Marshall DeLuca
Business Editor
In order for Western Australia to compete globally for participation in the country's oil and gas industry, reform of the tax structure will be necessary. Keith Hunter, Group General Manager for Operations and Technology for BHP Petroleum issued the request at the Offshore Western Australia Conference in Perth.

The industry could double in size with the right tax structure, Hunter said. Also, he called on producers currently engaged in exploration and production there to assist in the process and help foster growth.

In the keynote address, Hunter provided some insight into the current state of the Australian offshore sector, the key factors that have influenced its development, and the necessary components for industry's future growth.

"While in the past, the Australian industry has grown on the basis of locally derived technical solutions, we are now at a stage where we must apply the best technology on offer to enable us to unlock the resource potential from offshore Australia and thereby create wealth for all stakeholders."

The following is a summary of his remarks:

Current state

The Australian E&P industry is relatively small and immature. This is best evidenced in an accompanying chart comparing the total number of Australian producing fields to the UK continental shelf, Gulf of Mexico, and deepwater Gulf of Mexico. As is shown, Australia has 32 fields in production. This is similar to the total number of producing fields in the deepwater Gulf of Mexico (26).

The immaturity of the industry can be attributed to a number of factors.

(1) The majority of the areas offshore hydrocarbon resources are gas, albeit Australia has a very limited domestic gas market with most demand capable of being supplied by onshore discoveries or production from the Bass Strait. In the 1970s, most E&P companies regarded the northwestern region of Australia as being gas prone, and with a small domestic market, the LNG business was not economical. As a result, very few wells were drilled. This is due to Australia's relatively small population, limited minerals processing activity, and highly regulated gas market.
(2)The recognition of the offshore sector's potential was only recently realized. Until the discovery of the Timor Sea oil fields in 1983 and 1984, Australia's oil potential was thought to be confined to onshore and the Bass Strait, regardless of the fact that oil had been in production on Barrow Island for several years. Also, prior to the early 1980s, government policy was designed to facilitate self-sufficiency using import parity pricing rather than encouraging the development of Australia as an oil-exporting province.
(3)The third factor contributing to the immaturity of the industry is that the offshore sector, in production terms, has been dominated by only two world class assets - the Bass Strait and the Northwest Shelf.

Bass Strait

The Bass Strait was discovered in the mid-1960s in the offshore Gippsland Basin and supplies around 40% of Australia's oil production requirements. The fields in the Bass Strait have produced over 3 billion bbl of oil and 3.8 trillion cu ft of gas. Production peaked in the early 1980s at 500,000 b/d of oil and has been in a state of decline since.

This decline has been offset by infill drilling, which has added about 110 million bbl of production, and the bringing of more fields onstream such as the Bream B and West Tuna, which have also contributed 110 million bbl of new reserves. This has caused a major reversal in the region's production decline. Over the recent months, production has averaged over 230,000 b/d gross, 20% higher than levels achieved a year ago.

Further infill drilling is planned along with the phased development of the Blackback Field. The Blackback is located in water depths between 300-600 meters and will be the deepest production in Australia. This and other gas developments planned for the region in the early next century prove that the Bass Strait is a maturing asset to Australia's liquid production.

Northwest Shelf

The Northwest Shelf LNG gas and liquids project is the second major offshore development. The Northwest Shelf is at a different stage of its evolution with significant potential for expansion.

The expansion is based around the requirement of adding two further LNG trains and up to 7 million tons of additional production in the early next century. However, this project will require the expansion of domestic gas sales, onshore facilities, offshore expenditure, the addition of a second trunkline, new ships, and the ability to stream further liquids through existing production. This has resulted in the need for a major new wave of capital expenditure. BHP, a one-sixth equity holder in the project, has already planned expenditure in the vicinity of A$2 billion.

Timor Sea

The magnitude and extent of other offshore developments has been relatively limited. BHP has been involved in the development of the Timor Sea fields including the Jabiru, Challis, Skua, and Griffin, which are now rapidly maturing. The development of these fields was brought about through the use of what was then considered novel technology - specifically the use of floating production, storage and offloading (FPSO) systems.

The Timor Sea fields pioneered the use of FPSOs in the industry. BHP installed its first FPSO on the Jabiru Fields in 1986; this was long before FPSO technology had been acknowledged by the industry as a standard method of production.

The company's second FPSO installed on the Challis Field, was brought onstream at the same time that the Petrojarl was introduced in to the North Sea. These installations demonstrated that FPSOs could handle large throughputs in heavy weather conditions. It also contributed in developing the first FPSO capable of handling and treating gas to sale specification offshore.


Regardless of the immaturity of the sector, Australia, like the UK and the US, is increasingly shifting exploration expenditure to higher potential offshore exploration plays and away from the mature onshore basins of limited prospectivity. About 85% of Australia's exploration expenditure is offshore.

Offshore Western Australia and Northern Australia now account for the major proportion of Australian exploration and development expenditure (72%). Australia has further committed itself to the offshore sector with 66% of expenditures in development and production, a majority of this being in Western Australia.

While these expenditures are impressive, they are still barely sufficient to replace existing annual production. In order to compete for investment funds against the rest of the world, several things have to be addressed and appropriate actions taken.

Key influences

The key influences on the Australian offshore sector are capital flows, an undeveloped infrastructure base, labor costs and jobs, and taxation.

  • Capital flows: The relatively small size of the Australian offshore industry has meant that capital flows have been low in comparison with international terms. Australia's total on and offshore expenditure for the period of 1995-1996 was approximately $2.4 billion. This is only 3.5% of the world's total capital expenditure ($65.9 billion). Capital flows in the industry have also been volatile. In a small market, such as Australia, volatility makes it very difficult to build capability.
  • Undeveloped infrastructure base: Capital flows have resulted in a limited infrastructure. Australia has a major shortage in world class fabrication yards, and industry experienced personnel. This has led to construction and installation costs higher than overseas alternatives (fabrication yards in Southeast Asia).
  • Labor costs and jobs: Labor costs and productivity are only one component of a project's cost. However, in the case of the Northwest Shelf LNG expansion, 3-5 LNG trains and 11-12 million man hours will be required. At a labor rate of $80/hr, for example, in addition to higher domestic fabrication costs, the relative efficiency of investment expenditure is compromised. The industry cannot support the high wage rate with low productivity. In addition the lack of at least one excellent, competitive facility is a major handicap to the future of the supply side of the E&P business.
  • Taxation: The importance of a stable, reasonable tax regime cannot be overstated. In the offshore sector the Australian taxation regime has been assessed by the E&P industry as reasonably competitive in an international context. This is particularly true for the type of conventional oil plays as in Australia. The situation for large gas developments, however, is not as rosy.
The government uses the resource rent tax (RRT) legislation, which, in the case of a large gas project, poses a serious impediment - especially in a low inflationary climate. The RRT applies what can be considered an excess profits tax at levels just above or below the cost of capital for most E&P companies. This consequently makes it very difficult to make multi-billion dollar investment decisions, especially if there is significant market and technical risk.

However, the petroleum resource rent tax regime for deepwater and integrated gas projects is currently the subject of a very necessary review by an international consultant. The commonwealth government has initiated this review and an outcome is expected by mid-year.

A favorable alteration to the taxation regime for deepwater and new gas developments, due to the notable industry trend to those markets, would be a major boost to enable Australia to develop as a competitive player in world terms. It is important that regulators remain aware of the internationally competitive context of industry investment and expenditure and the imperative to continue to attract investment to the industry.

It is imperative for the growth of the Australian industry that it recognizes the trend to deepwater in terms of investment in land, seismic, rig building and conversion, drilling, and production activity.

A recent Salomon Bros. survey illustrated that two of the major factors driving E&P spending are attractive drilling prospects and recent drilling success. The level of tax take directly affects the availability of discretionary cash flow for this type of investment.

Accordingly, many countries have recognized that fiscal terms need to be differentiated for factors such as oil quality, production costs, geology, and in particular water depths.

Australia is an expensive region for deepwater exploration. Well costs are estimated to be 50-100% greater than comparable estimates in the Gulf of Mexico. This is due largely to mobilization, demobilization, and manning costs.

Returns from production are also much lower in Australia than other regions of the world. Australia's offshore sector represents the lowest return to investor and the highest relative level of government take. As a result, Australia's deepwater activity is not at the level it should be.

Preliminary geological studies have suggested there is substantial undiscovered potential in Australia, with the largest potential in untested deepwater area. Clearly increased activity in deepwater would lay the basis for increased activity in the development and production end of the business. For this to happen, special taxation treatment is needed for these areas. This tax reform could double the size of the industry.


Notwithstanding the difficulties, the industry has attracted significant levels of foreign investment. Development costs on a per-bbl basis have been competitive internationally. The region has good geology with highly productive reservoirs resulting in very good well productivity. This has helped offset many of the difficulties described earlier.

Development cost per bbl of reserves has also been competitive and the capital intensity, measured as investment $/b/d of production capacity, has been low. This has proven that Australian performance is substantially more competitive than the UK continental shelf and is in line with the deepwater Gulf of Mexico costs.

Excellent discoveries such as Perseus, Gorgon, Chrysaor, Laminaria, and the large Bayu-Undan Field in the Zone of Cooperation Area (ZOCA) between Australia and Indonesia have also spurred interest in the region. This, compacted with merger and acquisition activity, specifically Mobil's acquisition of Ampolex, has stimulated international interest.

Another key stimulus to the Australian industry is its relative geographic isolation from the mainstream international E&P sector and unique nature of the reservoirs. This has meant that Australian companies have had to be innovative and, in effect, had to "home-grow" expertise. In the case of BHP, it was in floating production and subsea technology in the 1980s. This will help in the future by creating a technological trade-off between Australia and the rest of the world.

The future

The future influence and direction of the industry shows the following:
  • Australia's perceived geological prospectivity remains sound.
  • There is a stable political system, fair and even-handed approach by governments in dealing with the industry.
  • Lack of corruption.
  • An ability to further access the markets of Asia.
There are a number of significant new developments committed or in the scoping and pre-development stage.

An accompanying graph shows a conservative estimate of some current and future offshore projects and estimated capital expenditure. The near term future shows development expenditure around A$2.0-2.5 billion. The decline past 2003 can probably be attributed to "planners droop." Also apparent is that due to planned capital expenditure, the ZOCA region will emerge as a leader by 2001. Some large projects due to be of a major factor in the near term are:

  • Laminaria and Corallina Field developments using an FPSO.
  • Northwest Shelf LNG domestic gas and liquids expansion which has the potential to double Australian LNG production from 7.5 to 15 million tons per year.
  • Bayu-Undan in the ZOCA area which involves complex liquids extraction and gas reinjection involving a conventional two 8-leg steel jackets housing drilling, production, and processing equipment. This project will provide major procurement, fabrication, and installation opportunities to both Australia's and Indonesia's offshore sector. The first phase is designed to access 350 million bbl of condensate and LPG, and the downstream phase will access over 3 Tcf of gas.
    Some smaller projects include:
  • Buffalo oil development in WA-260-P.
  • Elang-Kakatua in the ZOCA.
  • Blackback Phase I in the Bass Strait.
The greatest challenge for the industry will be to look further into the future in an attempt to identify new directions for the development of the Australian offshore sector. This direction will be critically influenced by the nature of the resource base, which is available, but also by emerging technological and market solutions for the application of energy.

Australia is a good place to conduct E&P operations. The geology is good, the politics are stable, the support industry can be competitive, and new technology is easily accepted.

In the near term, investment will continue at the rate of A$2.0-2.5 billion per year. Exploration expenditure will probably decay from its current level of circa A$750 million per year in the absence of a tax reform. Without changes, however, the industry will remain at its current small, immature level. There are obvious opportunities that could make Australia one of the major players in the international market.

Copyright 1998 Oil & Gas Journal. All Rights Reserved.

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