Energy and Government Policy in Western Australia

Energy Forum Papers

ENERGY IN WESTERN AUSTRALIA

THE WA ECONOMY

The Western Australian economy is currently experiencing near-boom conditions.  Since 1993-94 State annual real income growth has averaged over 6 per cent, a rate which is projected to be maintained into the future.  The main impetus for this growth has been the State's mineral resources.

ENERGY AND THE WA ECONOMY

Western Australia has a considerable potential in energy intensive industries.  The vast size of the State, its abundant mineral wealth and its relative isolation from the rest of Australia and from major markets makes it well suited for the processing of raw materials.  Local processing reduces the bulk and weight of basic products, thereby allowing them to be delivered to markets at lower cost.  For the State itself, local processing is the key to enhancing the value of the mineral (and agricultural) products of the State and improving employment within the State.

Cheap energy is vital to allowing increased local processing.  For alumina, energy accounts for some 20-30 per cent of total costs, but energy accounts for a high share of costs in many other industries, including chemicals, mineral sands, and iron and steel.

ENERGY TRENDS IN WA

Growth of energy consumption in WA has been considerably higher than in Australia as a whole over the past two decades.  In the period 1979-80 to 1995-96, energy consumption in WA increased at 4.8 per cent per annum compared with 2.3 per cent for Australia as a whole.  ABARE projects an acceleration of growth for WA to 5.6 per cent per annum for the years to 2003.  Figure 1 depicts these trends.

Figure 1:  Actual and Projected Energy Consumption Growth

The rapid past and projected growth in WA electricity and gas energy consumption compared with Australia as a whole is more clearly illustrated by the growth of energy excluding petroleum products.  This is shown in Figure 2.

Figure 2:  Energy Consumption (excluding petrol)

The greater part of this growth is forecast to be supplied by gas.  The State-owned generation business, Western Power, is the major coal user and has 1160 MW of coal-fired generating capacity at Muja and Bunbury, plus 900 MW capacity at Kwinana, which uses coal, gas and fuel oil.  There is a further 800 MW of Western Power plant fuelled mainly by gas (the most important being at Pinjar), and considerable gas-based cogeneration supplied by other parties.  The BP/Mission plant, under a 25-year contract to supply its surplus energy to Western Power, is the most significant of these.  Present power plant is shown in Table 1.

Table 1:  Western Power Generation Plant

Station	Fuel	Capacity (MW)	Commissioned	1995-96 Energy (GWh)
South-west
Bunbury	coal	120	1957	251
Muja A&B	coal, oil	240	1965	1758
Muja C	coal, oil	400	1981	2828
Muja D	coal, oil	400	1985	3329
Kwinana A&C	coal, gas, oil	640	1970-76	2307
Kwinana B	gas, oil	240	1970	900
Mungarra	gas	112	1990	428
Pinjar	gas, oil	499	1990	591
Other SW	-	86	various	13
BP/Mission	-	116	1996	-
Other	-	201	-	302

Source:  Western Power, Annual Report.

The Collie-A 300 MW coal-fired station is to be commissioned in 1998 partly as replacement for older coal stations;  it is likely that further electric power will be gas-derived, both from dedicated stations of Western Power and others, and from cogeneration plants.

Compared with 1995-96 levels, gas demand is expected to grow by 70 per cent to 446 Petajoules (PJ) in 2000-1 and over 140 per cent to 631 PJ in 2004-5.  By contrast, coal is expected to increase by only 10 per cent over the entire period to 137 PJ.  Accordingly, in 2004-5 gas will be responsible for 4-5 times the power consumption of coal.  Figure 3 below illustrates the trends.

Figure 3:  Forecast Demand Growth for Gas and Coal

GEOGRAPHIC STRUCTURE OF THE WA ENERGY MARKET

The WA market for energy falls into three main regions.  These comprise the area from Dampier to Port Hedland centred on iron ore;  the interior strip from Newman to Kambalda with iron ore, gold and nickel;  and the coastal area from Geraldton to south of Bunbury with mineral sands, alumina and the industrial demand of the Perth region.

Gas is the key to supplying future demand growth.

• Demand in the north west is presently around 40 Terajoules (TJ) per day (14 PJ per annum) but is expected to grow to over 200 TJ/d (73 PJ per annum) over the next five years.
• Demand along the Goldfields pipeline is presently 60 TJ/d but expected to grow to 150 TJ/d over the next five years, much of it by displacing power delivered by Western Power, effectively from coal.  The 150 TJ/d level approaches the pipeline's fully compressed capacity.
• Demand from Geraldton to the south is presently 530 TJ/d and expected to grow to over 800 TJ/d in the next five years.  The DBNG pipeline has a capacity of about 500 TJ/d and the WANG pipeline about 65, expandable to 100 TJ/d.

MAJOR PROJECTS DRIVING ENERGY DEMAND GROWTH IN THE SOUTH-WEST

Power for processing raw materials accounts for the great bulk of the projected increases in energy demand.  There is a number of planned projects in the north of the State which are to add value to iron ore deposits using gas or gas-derived electricity from the NW Shelf.

There is also considerable activity in the south of the State which will require increases in power.  The most important such activity is alumina, which accounted for 40 per cent of gas usage in 1994.  Alcoa presently consumes around 75 PJ per annum of gas at three refineries in the south-west.  Capacity increases are planned and although the business is steadily improving its energy economy, an additional 10-20 PJ will be needed by 2005.

Worsley alumina primarily operates using coal (about 14 PJ) with about 4 PJ gas.  Refinery upgrades are forecast to double the gas usage.

Other major projects connected with mineral deposits include:

• Asia Iron direct reduction east of Geraldton, which would use about 31 PJ in 2002 if it proves bankable.
• Kingstream near Geraldton is likely to be in production by 2000 and will require over 50 PJ of gas at that stage and double that (340 TJ/day) five years later.

An expanded load growth in the Perth region is also forecast to occur as a result of a great many relatively small projects and increased household demand.  The likelihood of increased production activity is partly dependent on costs, including energy costs, being competitive with those in rival locations.

PERFORMANCE OF THE GAS AND ELECTRICITY SUPPLY INDUSTRIES IN WA

Electricity

The growth of utility-derived power in WA has taken place notwithstanding a relatively indifferent performance by the former SECWA in terms of cost efficiency.

WA suffers from having to service a larger area than other States.  Even so, in terms of the industry's normal cost criteria, the electricity supply industry is a poor performer compared with other Australian systems, which in turn lag considerably below the performance of those in North America. ⁽¹⁾

In terms of generation, Table 2 shows that WA's capacity factor (generation divided by installed plant capacity) indicated far greater excess capacity than other States and in 1994-95 WA also required three times as many employees as NSW and twice as many as Victoria to produce each unit of electricity.  Both these State systems have vastly improved productivity in the years since 1994-95.

Table 2:  Generation Performance Data (1994-95)

State system	Load factor (%)	Capacity factor (%)	Reserve plant margin (%)	Equivalent availability factor (%)	Labour productivity (GWh/Employee)
New South Wales	63.2	52.7	38.3	87.5	34.1
Victoria	67.6	58.7	36.4	90.5	24.8
Queensland	73.6	72.4	25.9	93.5	18.8
South Australia	53.7	41.7	5.4	87.6	13.3
Tasmania	71	39.6	79.3	87.2	48.7
Snowy Mountains Authority	20.7	16.8	21.8	87	10.8
Northern Territory	67.9	41.9	62.1	-	7.2
Western Australia (Western Power)	65.8	47.5	35.6	87.1	11.9

Source:  Electricity Supply Association of Australia (ESSA), Electricity Australia, 1996.

In terms of overall operations and maintenance costs, Western Power was less adversely placed than in its performance as a generator.  Nevertheless, its costs were considerably above those in the Eastern States -- and again, both NSW and Victorian generators have reduced costs considerably over the years since 1994-95.  In both States, the average price at which energy was sold into the pool was less than $25 per MWh during 1996, a level that is below their estimated costs in 1994-95.

Table 3 illustrates comparative cost data.

Table 3:  Generation Costs in State ESI's (1994-95)

State	O&M Costs $/MWh (excluding fuel & fixed costs)	O&M Costs $/MWh (including fuel & fixed costs)
NSW	6.9	27.1
VIC	8.2	45
QLD	6	32
SA	7.2	42.3
TAS	3.7	33.3
NT	35.9	124.7
WA	7.7	63

Source:  ESAA 1996

In transmission, WA enjoys low costs per circuit km, but again has higher costs per unit of energy than the other States.  This is shown in Table 4.

Table 4:  Performance in Transmission

State	Labour Productivity (GWh/Employee)	O&M Costs $/GWh (Including Fixed Costs)	O&M Costs $/circuit km (Including Fixed Costs)
New South Wales	41.7	5.7	9890
Victoria	85	4.7	25800
Queensland	52.2	2.9	9165
South Australia	48.1	3.4	5699
Tasmania	47.3	5.3	12050
Western Australia	19.8	10.2	9015

Source:  ESAA 1996.

Western Power does not report its average industrial tariffs in a way that can readily be compared with other States, but overall prices tend to be more than 10 per cent above those of the Eastern States.

Gas

Gas prices in WA are low by the standards of other States.  Table 5 shows that they are comparable to those in South Australia and Victoria and considerably below NSW and Queensland.  (The prices below are actual prices based on average revenue rather than tariffs).

Table 5:  Average Price to Commercial and Industrial Customers ($/GJ)

	1992	1993	1994	1995
NSW	5.72	5.76	5.79	5.59
Vic	4.14	4.25	4.22	4.26
Qld	7.22	7.53	7.56	7.71
SA	3.9	3.96	3.9	4.01
WA	3.93	4.22	3.89	4.08

Source:  Australian Gas Association (AGA), Gas Statistics, 1996.

The low cost of gas in WA has brought it a high share of the non-transport energy market.  With 57 per cent of the market, gas in WA far exceeds the share in States other than Victoria (which has an extensive domestic reticulation load and a climate that favours gas for heating).  Table 6 illustrates this.

Table 6:  Gas Share of Non-transport Energy Market

	1991	1995
NSW	16	17
Vic	55	57
Qld	11	11
SA	42	43
WA	53	57

Source:  AGA, Gas Statistics.

According to the WA Office of Energy, ⁽²⁾ of the 196.5 PJ that was transported by pipeline for domestic use in 1994-95, 91 PJ (46 per cent) was used for electric power generation.  (Although some 6 PJ of this was refinery and LPG plant use.) Gas has a larger share of inputs into electricity production than coal;  as a share of electricity output it would be higher still if gas plant is converted to combined cycle with its superior production efficiency (up to 50 per cent compared with 30-40 per cent for coal).  Figure 4 shows the share of different fuels in electricity inputs.

Figure 4:  Primary Energy Share of Electricity

Somewhat oversimplifying the non-transport market into coal and gas, gas in WA is estimated to comprise over 70 per cent of this market in 2004-5.

Factors in Gas Prices

Gas Availability and Prices

Gas prices to customers depend on the price of the gas at the well-head and on transport costs.  The well-head price is a function of costs of production and competitive alternatives, including gas-on-gas competition.

Natural gas in WA is largely produced in two major basins:

• Carnarvon Basin at 644 PJ per year and
• Perth Basin at 14 PJ per year.

Carnarvon Basin producers include several consortia of rival firms.  The gas supply is, however, dominated by the NWSGP with a break-even price to the main pipeline believed to be about $1.65/GJ.  Smaller fields could be brought into operation with a lower break-even price.

WA gas at the well-head is much cheaper than that found elsewhere in Australia (and the reserves are massively more extensive).  Although Victoria has contracted gas from Bass Strait at some 30 cents per GJ, the government taxes the gas to bring its price to a level of about $2.35, which is the price for new gas.  Gas from the Cooper Basin is more expensive than this, although ETSA of South Australia has negotiated a delivered price believed to be around the $2.35 per GJ level.

Gas Transportation

The DBNG pipeline is the key infrastructure for the transport of gas in WA and has a virtual monopoly on transport to the south-west.

WA's gas price advantage is reduced by the 1,500 km distance the gas from the NW shelf must be transported along the DBNG pipeline to the south-west.  In addition, the costs of transport are higher than for comparable systems.

Operational costs can be derived from annual report data.  These show that the average price of transport, excluding contributions to capital, for the DBNG pipeline is 27.4 cents per GJ, which is more than twice that of Victoria's GTC, and 50 per cent above the costs of the NSW and SA transmission systems.  This is despite the fact that the DBNG pipeline in 1995-96 was operating at 81 per cent capacity, much closer to its maximum than the other major transmission pipelines in Australia.

Operating costs are shown in Table 7, and Figure 5 illustrates the high cost per GJ kilometre of the DBNG pipeline.

Table 7:  Operating Costs of Major Australian Pipelines, 1994-95

Pipeline	Length Km	Capacity (TJ/day)	Operating cost ($m) per year	Average Day Throughput (TJ)	Costs per GJ (cents)
DBNG	1950	486	39.626	396	27.42
Moomba-Sydney (TPA)	1960	390	17.982	266	18.52
Moomba-Adelaide (PASA)	1989	315	15.486	236	17.98
Victoria (GTC)	2330	1000	20.674	550	10.3

Source:  Annual Reports covering 1994-95, except TPA which is 1993-94.

Figure 5:  Operating Costs of Major PipelinesSource:  Derived from ABARE, Energy 1997:  Projections

The pipeline's high operating costs are further amplified by high capital costs.  In part, these result from some "goldplating" of the pipeline when it was originally built and from high financing costs because of Yen-financed debt which was unhedged and suffered from a strong Yen appreciation against the Australian dollar.  Debt remaining on the pipeline is close to $1 billion.

The price for Tranche 1 access (98 per cent probability of supply) are $1.26/GJ ($1.03 reservation charge and $0.23 commodity charge) ⁽³⁾ where the load factor is 1.0;  and $1.37/GJ where the load factor is 0.9.  For Tranche 2 availability (92-98 per cent probability of supply) the charge is $1.21/GJ.  These prices are double those charged by GTC and considerably above the PASA and EAPL tariffs. ⁽⁴⁾ They largely negate the advantageous price WA customers have as a result of their access to relatively cheap well-head gas.

The pipeline is to be sold as an open-access pipeline in 1997 or 1998, and a steering committee has been established to implement the sale.  The Minister, having first expressed a preference for a partial sale, has recently agreed to a full sale.

Full haul capacity is fully committed in contracts with Alcoa, Alinta Gas, and Western Power.  Compressor augmentations will shortly lift capacity by about 8 per cent.  This too is fully committed.  Tranche capacity (TJ/day) commitments from 1999 are shown below:

Tranche 1
Alcoa	211
AlintaGas Trading	167.5
Western Power	28.5
East Spar	10.2
NWSG	8.8
Total	426
Tranche 2
Western Power	41.5
Tranche 3 Reservation
Western Power	20

The gas specification of the line is heavily influenced by the nature of the gas from existing sources and the high LPG content which is stripped out at Wesfarmers plant at Kwinana.  About 0.2 PJ of tempered and simulated liquid petroleum gas is supplied for reticulation in Albany and Mandurah.

The Wesfarmers contract has considerable implications for competitive sources of gas wishing to use the DBNG pipeline.  The pipeline stipulates that gas must contain at least 1.45 tonnes of LPG per TJ or the shipper must pay compensation to Wesfarmers based on the world price of LPG (currently about $400 per tonne).  This severely restricts the ability of fields like Tudbridgi and Harriet to market their gas.

THE NATIONAL REFORM AGENDA

THE HILMER REPORT

The microeconomic reform process which is driving structural change in the Australian electricity industry commenced before, but is consistent with, the recommendations of the report of the Committee of Inquiry into National Competition Policy, commissioned by the Australian Government in 1992 (the Hilmer Report).

Previous government inquiries had established that there was considerable scope for increased efficiency and competition in the Australian electricity industries.  The Hilmer Report pointed out that the introduction of effective competition into markets traditionally supplied by public monopolies often required more than the removal of regulatory restrictions on competition.  The excess market power held by such public monopolies is likely to impede the introduction of effective competition, and therefore reform requires the dismantling of monopolies in addition to the removal of regulatory restrictions on competition.

The Hilmer Report identified three separate types of structural reform which may be required in any particular industry:

• the separation of regulatory and commercial functions which could otherwise create a potential conflict of interest in a competitive market;
• the separation of natural monopoly elements from potentially competitive activities, because control over access to a natural monopoly might be used to stifle or prevent competition in the market, or if not exercised in that way the potential to do so may deter new entrants into the market;  and
• the separation of potentially competitive activities by splitting or dismantling entities with substantial market power into a number of distinct competitive entities capable of competing with each other.

COUNCIL OF AUSTRALIAN GOVERNMENTS

In April 1995, the Council of Australian Governments (COAG) signed the National Competition Policy (NCP) Agreements ⁽⁵⁾ which adopted the recommendations of the Hilmer Report and formalised the Governments' intent to promote a more competitive domestic trading environment and improve Australia's position in the international market.  To that end, the NCP Agreements lay down a set of principles for the structural reform and prices oversight of public monopolies and hence have significant application to the electricity and gas supply industries.

Electricity

The guiding objectives determined by the COAG in the building of the national electricity market (NEM) were:

• freedom of choice for electricity buyers;
• non-discriminatory access to the interconnected transmission and distribution networks;
• merit-order dispatch based on bid price;
• no discriminatory legislative or regulatory barriers to entry for new participants in electricity generation or retail supply;
• no barriers to inter-state or intra-state trade;  and
• uniform and cost-reflective grid pricing.

Although not a party to the NEM, Western Australia is to implement a reform programme consistent with it.

Gas

Detailed decisions were taken on free and fair trade in gas at the February 1994 COAG meeting in Hobart.  These included agreement on a national framework with no legislative or regulatory barriers to both inter- and intra-jurisdictional trade in gas.

Subsequent work has progressed on a National Third Party Access Code.  This involves the injection of considerable bureaucracy into the decision-making of businesses seeking to build new pipelines.  In particular, it places a public official as the arbiter of the price of access, and offers little discretion to a builder of a new pipeline to seek to price at what the market will bear.  This will introduce constraints on the incentive entrepreneurs have to seek out less than assured projects with high rewards where they are successful.

In addition, as discussed later, the price-setting process is highly prescriptive and adopts a price-based regulatory approach rather than one that seeks to encourage maximum use of the capacity and the building of additional capacity.

However, as the administrator of the access system, the National Competition Council has discretion to cease "coverage" of a pipeline where there is competition in the form of rival pipelines.

ADOPTION OF HILMER AND COAG INITIATIVES VIA SPECIAL PAYMENT MECHANISM

One of the measures agreed to in the NCP Agreements was the development of an interim competitive NEM during 1997 and completion of the transition to a fully competitive NEM by 1 July 1999.

The incentive, to meet this deadline, was provided by the NCP Agreements themselves.  Under the NCP Agreements, the Commonwealth agreed to make special payments to States and Territories which made satisfactory progress in implementing the national competition policy reforms.  If a State or Territory does not take the required action within the specified time, its share of the payments will be withheld.  The National Competition Council (NCC) will assess, prior to 1 July 1997, 1 July 1999 and 1 July 2001, whether the conditions for payments to the States and Territories, to commence from those dates, have been met.

The money which has been allocated to these special payments is set out in Table 8 below (estimated nominal $ million).  WA's share of the total is approximately $1.6 billion.

Table 8:  Competition Payments

1997-1998	428
1998-1999	646
1999-2000	1113
2000-2001	1369
2001-2002	1888
2002-2003	2184
2003-2004	2499
2004-2005	2833
2005-2006	3188
TOTAL	16147

Source:  National Competition Council Brochure (Oct.1996)

PROGRESS TO DATE

The National Electricity Market (NEM)

The NEM was first scheduled to commence on July 1994.  The scheduled commencement date has been deferred a number of times.  It was determined in late 1996 that there would be a staged implementation of the NEM.

NEM1 Phase 1 commenced in May 1997 and links the Victorian and New South Wales markets.  It involves:

• electricity flowing in and between the State markets based on competitive bid offers received in both markets;
• initial limits on flows between markets which will be progressively removed;
• power system security responsibilities remaining with each State;  and
• separate Snowy-Hydro Traders in each State managing the bidding into each State market.

The fully operational national market (NEM3) is anticipated to start in early 1998, after the Code is authorised by the Australian Competition and Consumer Commission (ACCC) and accepted as an access undertaking and once the National Electricity Market Management Company (NEMMCO) has fully tested and taken delivery of the national market systems.

Legislative and Regulatory Developments

In May 1996, the Governments of New South Wales, Victoria, Queensland, South Australia and the Australian Capital Territory agreed to introduce the NEM through legislation to apply in each jurisdiction.  In June 1996, South Australia enacted "lead legislation" containing the National Electricity Law (which in turn provides for the establishment of the National Electricity Code).  The other participating jurisdictions are now in the course of preparing their own "application legislation" to apply the National Electricity Law and the Code.

The Code has been prepared through a consultative process conducted by the participating jurisdictions and involving industry participants.  The Code was submitted to the ACCC in December 1996 for authorisation under Part VII of the Trade Practices Act.  Accompanying the Code was a draft access regime, which is also being examined by the ACCC pursuant to Part IIIA of that Act.

THE NATIONAL GAS MARKET CODE FOR THIRD PARTY ACCESS

The gas Code is to implement the February 1994 COAG agreement on free and fair trade in gas and the competition policy reforms and the confirmation of these agreed at the meeting in April 1995.  The 1995 agreement brought the arrangements under the ambit of Part IIIA of the Trade Practices Act which provides for an access right for significant infrastructure of national significance.  The gas Code amplifies twelve principles established in the 1994 agreement.  Importantly these specify that:

• there should be a uniform framework for access to transmission pipelines;
• all legislative and regulatory barriers to trade should be removed;
• government owned utilities should be placed on a commercial footing;
• natural monopoly elements should be separated or ring-fenced;  and
• distribution franchises should be reformed.

Open access to transmission has since been interpreted to encompass distribution.  This means exclusive existing franchises must disappear, but the timing of this has not been stated, and that there are to be limitations on any new franchises.  Third-party access arrangements are now in operation in WA.

The identity of the regulator is not yet agreed although the overall arrangements will fall under the Part IIIA of the TPA and the Regulator is eventually likely to be the ACCC.  There is also to be a Coverage Advisory Body (which is envisaged to be the National Competition Council (NCC)), a Decision Maker (the responsible Minister, either State or Commonwealth) and an Appeal Body.

The Code requires an owner of a declared facility (which will include almost all pipelines) to lodge access arrangements with a regulator.  The regulator may, after seeking comments from interested parties, require the arrangements to be modified.  The arrangements are to cover:

• access conditions and availability;
• services and reference tariffs;
• pricing principles;
• ring-fencing;
• information disclosure;  and
• arbitration arrangements in the event of a dispute.

Specific Provisions

A prospective service provider may seek a non-binding opinion from the coverage advisory body (1)(31) and apply to the regulator for approval of a proposed access regime (2)(13).  The latter may be modified by the regulator.  The decision of the regulator becomes a determination.

The Access Arrangement

The Access Arrangements must include a policy on haulage, one or more prices for a significant part of the service, trading capacity policy and allocation of spare and developable capacity.

• The reference tariff must comply with principles that are related to costs.  The services must be unbundled.
• An existing pipeline's initial capital base is determined at the start of the reference period and includes the capital base at the start of the preceding period, new expenditure, less depreciation, less identified redundant capital.  The initial capital base takes the value less accumulated depreciation and the regulator has considerable latitude on whether to use an optimised depreciation cost methodology, or another recognised valuation methodology.
• New Pipelines take the cost as the tariff base.  It is not permitted for providers to front-end the tariff to protect themselves from later competition or to impose excessive costs on users.  The costs as determined by the regulator establish the price and this means the builder takes the risk that the tariff will eventually cover costs.  Moreover, the depreciation used to establish costs need not apply "depreciated optimised replacement cost" but could, at the discretion of the regulator, be based on historical costs.
• The secondary trading policy must extend beyond bare transfer, which does not need any consent;  where substitute transfer changes the end points or other matters, the service provider's consent is necessary but this can only be denied on reasonable commercial or technical grounds.
• A queuing policy is required for spare and developable capacity.
• Ring-fencing is to be in place so that the service provider only carries out a transportation business.  This ensures confidential information is not divulged, that affiliates are not favoured and that costs are fairly apportioned.

The Code as a Vehicle to Promote Greater Efficiency

The Code is highly prescriptive in terms of the conditions stipulated for access to pipelines.  The regulator establishes the price.  Although such measures may have a place in the case of existing pipelines that were either built by governments or were built with a de facto franchise, they are likely to be disincentives to the building of pipelines other than those that carry a negligible risk of financial failure.

In specifying prices and access arrangements, a regulator is likely to specify a "fair" price.  Commonly this will be below the market clearing price -- a point tacitly acknowledged in the stipulations for a queuing policy.  Where maximum prices established by regulators are set too low, the outcome is a scramble for capacity and an unwillingness of suppliers to increase available capacity.  Both these outcomes amount to economic loss.

More significantly, the prescriptive nature of the Code will impede the development of higher risk entrepreneurial pipelines.  Such ventures involve strong returns (based on high prices) for success with a corresponding risk of poor performance if hoped-for demand is not forthcoming.  It is difficult to see provision for such pipelines in the Code as presently drafted, since a new pipeline's reference tariff is to be based on its capital costs.

In general, regulation of essential facilities is best focused on providing incentives to encourage capacity to be fully used and expanded where there is demand for this.  Instead, the Code's focus on price levels carries risks of distorting demand and is likely to prove impossibly complex in its operation as the regulator must address a considerable number of services and assets which have a plethora of different depreciation schedules forming the basis for the regulated price.

ENERGY POLICY IN WESTERN AUSTRALIA

POLICY AIMS

Energy policy is overseen by the Office of Energy which reports to The Minister for Energy.  The Government's aims are to:

• Reduce energy prices in the State;
• Ensure that adequate and reliable energy supplies are available;
• Encourage further private sector involvement in energy supply;
• Develop and promote a competitive energy industry by exploiting and developing synergies between energy and other industries;  and
• Ensure efficient use of energy resources and encourage sustainable development.

Although WA is not envisaged to be connected to the gas and electricity systems of other States in the foreseeable future, the State has willingly accepted the COAG reform agenda and is an active participant in developing the national access code for gas.

The first major step in creating a competitive market for energy and to facilitate genuine competition between gas and electricity was the creation of Alinta Gas and Western Power from the former SECWA.

DEVELOPMENTS IN GAS AND ELECTRICITY

Electricity

The opening up of Western Power's transmission system is presently underway.  Customers taking power from the 66kV lines presently have open access and these are to be joined by the 10 MW load customers in July 1997.  There is a phasing-in of open access for 5 MW customers up to July 1999.  These liberalisations cover the 20 largest customers of Western Power.

The Government also has a policy of fostering provision of additional capacity by businesses other than Western Power.

Gas

The DBNG pipeline has been administratively ring-fenced from other parts of Alinta's business.  This is a major step towards opening the market to genuine competition.  The move has been followed by allowing any customer taking at least 500 TJ/annum through a single metered connection to contract directly using a common carriage rate.  From the year 2000, industrial customers using over 100 TJ per annum may access a gas producer of their own choice, but no timetable has been announced for other customers to become contestable.  100 TJ/a customers comprise large factories like an integrated bakery.

APPRAISALS OF POLICY

General

With regard to energy policy outside of the Geraldton-to-Bunbury rectangle, WA has developed a deregulated approach that offers energy users considerable choice.  Inside the Geraldton-to-Bunbury rectangle, energy policy has progressed only slowly towards competitive provision.  Progress has failed to live up to the policy aims and the liberalisation process is lagging that of other States.

Electricity

Progress in WA in Relation to Other States

WA is very much behind the Eastern States in permitting electricity customers to opt for supplies by parties they wish to buy from.  In part this is due to the monopoly that Western Power has over generation.  Much of the nominally independent generation is tied up by Western Power;  thus, the Mission Energy-operated BP co-generation plant is a contracting-out process rather than a new competitor.  Other States are seeking to convert similar contracts into competitive power provision -- Victoria is presently arranging for this with Mission at Loy Yang B, whilst Queensland is undertaking discussions with Comalco over the Gladstone Power Station.

WA is similarly behind in opening the retail market.  Whereas the present limit of contestability in WA is the 5 MW market to be opened by 1999, NSW and Victoria opened up this tranche in 1994 and 1996 respectively.  By 1998, NSW and will have made all customers above 160 MWh per annum contestable.  This takes contestability down to small offices and fast food restaurants.  Queensland has a programme that is about three years behind the NSW and Victorian timetables.

All three of these eastern States have also divided up their retailer/distributors into competing entities which contend for retail customers.  There have been no announced plans in WA to disaggregate the distribution and retail businesses of Western Power.

Victoria has advanced faster than other States both in implementing market liberalisation and in ensuring private sector ownership.  All the Victorian system is now privatised or in the process of being sold to competing businesses.  Privatisation is the only way that fully commercial operations can be guaranteed.

National Market Requirements

The national market for electricity requires the structural separation of generation and transmission.  WA, with Western Power, has one business that is vertically integrated controlling the great bulk of generation, transmission, distribution and retailing.

The continued aggregation option was the approach initially favoured by South Australia.  Other jurisdictions claimed this to be contrary to national market principles since it would have given the integrated supplier, ETSA, market power, and an unfair advantage over other providers, an advantage that would ultimately impact adversely on the State's consumers.  South Australia agreed to a review by the Industry Commission (IC).  This has resulted in the disaggregation of generation from other elements of the industry.

South Australia, however, has kept its generation facilities under the same business, having persuaded the IC that it would be impracticable to operate its only two generators as independent entities.  However some 30-40 per cent of South Australia's power is imported through Victoria and a further link to NSW is being planned.

South Australia has no public plans to divide its distribution business into more than one entity and has yet to announce a market-opening schedule.

A key element in bringing lower customer prices is the availability of rival supplies.  New South Wales has keen competition with only three independent generators. ⁽⁶⁾

Consistent with the national market approaches and contemporary views of how to obtain greater efficiency in the electricity supply industry, WA should consider means of further disaggregating its generation industry and arrange for power to be bid by rival firms and be scheduled by an independent systems operator.  These firms should have independent boards and should be privatised at an early stage.

This approach presents some difficulties where there are only three main generators, each with a distinct set of costs and known position in the merit order.  The commissioning of the Collie station will allow greater competitive tension.  Even before that, however, there are opportunities to operate a power pool without this resulting in prices being ramped up artificially since all stations are heavily committed to take-or-pay gas and coal and cannot risk being scheduled off at times when they would normally expect to operate.

Gas

Goldfields Gas Pipeline

Access to the Goldfields Gas Pipeline is governed by a specific Act.  The pipeline has a monopoly on gas supplies but its owners face pressure from alternative power sources via Western Power.

The Goldfields Gas Pipeline, though nominally open-access, in fact grants comparatively favourable terms to its three sponsor businesses.  Other users are obliged to pay very much higher rates.  This has brought about some protests, including from Alinta Gas which is seeking to reticulate gas in Kalgoorlie.  If the pipeline were truly built as an entrepreneurial venture, the three businesses that financed it took some risk about its future profitability.  Those now seeking a lower price than that offered for the use of such a venture would not have shared in any of the losses had the pipeline been unsuccessful;  and in making use of its services they are better off than they would have been without any pipeline.

Although the present pipeline's owners might have wished to build it under such an entrepreneurial regime, it was in fact selected by the Government after successfully winning a tender process.  It was, therefore, developed with government patronage, which involved the removal of Government regulations that prevented enterprises building a pipeline.  The owners' case for a free hand in pricing is therefore weaker.

Nonetheless, the conditions under which the Government agreed to the pipeline proceeding gave wide powers to its owners with regard to prices charged and as a quid pro quo the owners agreed to build a larger capacity pipeline than they had intended.  To disturb such an agreement would give rise to "sovereign risk" issues.

Additional Pipeline Capacity to the South-west

The servicing of increasing customer needs in the south-west requires additional capacity.  The WANG pipeline from Dongara is capable of upgrade but the reserves it taps are insufficient to justify a major facility.

Two proposals for increased capacity are presently under consideration.  The first involves a looping and eventual duplication of the existing DBNG pipeline.  The second is for a rival pipeline to be built from the NW Shelf, a proposal that the US-owned PGT has made.

The easement within which the existing pipeline is located belongs to the Government (rather than its pipeline business) and presently has sufficient space to accommodate three pipelines and could be enlarged relatively easily to allow more than this.  Even so, the incumbent Alinta pipeline is, understandably, seeking to forestall the possibility of further competition by offering to supply key load expansions both in its own name and in association with EPIC, a US major, which is a likely bidder for the pipeline.  The proposed Kingstream project is the pivot around which such strategies are revolving.

In a market that is truly open, manoeuvrings of this kind are legitimate responses to the prospect of new competition.  The existing monopoly and the requirement for others to obtain a licence from the government means that the WA gas market is not truly open.  Moreover, there are risks in having the government-owned facility embark on its present strategic manoeuvrings.  The liabilities in the event of failure are pressed home to the taxpayer, rather than residing with equity holders.  Notwithstanding corporatised boards, government bodies are less likely to adopt prudent profit-maximising approaches to business than private sector bodies with genuine shareholders.

Pipeline Ownership and Approval Processes

It is very damaging if a government-owned facility enjoys special favours over private facilities.  But public sector businesses have easier access than private businesses to government ministers who are their shareholder representatives and the shareholding relationship is plagued by such potentialities.

Ensuring fully commercial operations would have been among the reasons why the Government is seeking a divestiture of the existing pipeline.  However, structural matters, both in terms of the pipeline's shareholding Minister and the committee charged with its divestiture, carry risks of the overall community interest being compromised:

• having the shareholding of the pipeline reside with the Minister for Energy is an approach that other jurisdictions have avoided because of the conflict of interest created if energy policy goals do not correspond with overall economic policy goals; ⁽⁷⁾
• the committee overseeing the privatisation of the pipeline comprises, in effect, three Alinta directors/officers, two energy/resource portfolio officials and only one official from Treasury.  This is in marked contrast to privatisation processes elsewhere which avoid the opportunity for, and perception of, conflict of interest by placing the process squarely within the Treasury/Finance portfolio.  The normal structural arrangements recognise that there are opportunities for corruption of the sales process where the committee responsible for obtaining the best price for the asset is also able to influence policies, like the approval of rival energy sources, that could artificially inflate its value.

There is capacity for any government to use its approval processes in favour of some parties and at the expense of others.  In the case of major pipeline developments, contracts for "lumpy" new loads are often crucial to justify building new capacity.  Statements attributed to the Minister for Energy have indicated his opposition to a rival pipeline being constructed while the Alinta pipeline sale process is in progress.  Such delays can seriously jeopardise the ability of a new pipeline to offer contracts and, in the case of the PGT proposal, may thereby frustrate the entire project.

In this respect, at the heart of the 1995 Competition Policy Reform Act and the associated intergovernmental agreements is the willing acquiescence by all Australian Governments to place all providers in the market place on an equal footing irrespective of whether they are publicly or privately owned.  This policy is based on generally agreed principles that competition at arm's length from government brings pressures to reduce costs and seek out new market needs for which government itself is not well equipped or sufficiently commercially motivated.

Implications of Withholding Approval for a New Pipeline to the South-west

A monopoly which faces competition in a previously sheltered market will automatically see some of its ostensible value reduced.  In an extreme case, the value could be almost totally eliminated, as is likely with many US nuclear plants once open markets allow power to be "wheeled" into their owners' franchise areas.  Protection of those assets is only possible by maintaining a price burden on customers.

By withholding approval for a rival facility, the Government would achieve a higher price for the existing pipeline.  This would be equivalent to the present value of the increased future income stream resulting from the monopoly prices during the period that the monopoly remains in place.  That higher price, however, would merely represent a tax imposed on consumers and businesses by Government regulation.  The tax would be paid by a transfer from businesses and consumers.  In the process, the market distortion resulting from the Government-enforced monopoly brings about an unambiguous loss of income and development in the State.

In terms of the price that the Government is likely to realise from the sale or partial sale of the DBNG, given intergovernmental agreements, it is most unlikely that a potential buyer would consider the monopoly at present held by the pipeline to be sustainable into the future.  Price offers will therefore respond to the public policy commitment.

In practical terms, the effect of a rival pipeline on the DBNG facility is likely to be cushioned by a number of factors:

• an additional pipeline of 500 TJ/d could not capture the entire market which is likely to be some 800 TJ/d by 2005 (and to grow in subsequent years if competitive prices for energy promote expansions in demand);
• contracts are locked in with Alcoa, Western Power and Alinta's retail arm until at least 2005;  (but the price at which the transport is provided, at least to Western Power and Alinta retail, is likely to come under pressure if a rival pipeline offers supplies of gas at a lower price);
• there are economies available to the operations of the DBNG pipeline and additional competition is likely to foster the adoption of these.

There may well be other areas of profit and loss emerging from a new pipeline.  Thus, if such a pipeline allowed increased competition between different gas fields, it would put additional downward pressure on the price to the final customer.  An outcome of this nature is possible because of the present inability of some fields to compete in the south-west market due to the high LPG content required of gas in the DBNG pipeline as part of the contract with Wesfarmers.

Western Power and Alinta Gas have take-or-pay contracts with the NW Shelf Joint Venture, which could have considerable implications if increased competition from cheaper well-head gas were to emerge.  The terms of the contracts are not public, but the outcome of downward pressure on well-head prices could be one or a mixture of the following:

• losses by the two State-owned businesses reflecting the degree to which competition forces them to reduce prices to customers (Alinta) or as inputs into electricity generation at their own plants (Western Power) which are saddled with high costs;
• reduced revenue for the NW Shelf Joint Venture if there are price renegotiation clauses in the present contracts.

Increased competition brings lower prices and enhanced gas usage including in value-added projects which become profitable at lower gas prices.  Gas users will be clear beneficiaries but it is almost impossible to predict the outcome of the swirling array of demand, supply and contractual arrangements on all of the parties.  It is, however, reasonably certain that constraining the forces of competition will mean higher energy prices than would otherwise prevail.  Higher energy prices mean a likelihood of choking off some of the expansion in energy usage that is predicted, including thwarting some of the value-adding activities that the Government is seeking to foster in the south-west.

All of this reinforces the need for governments to avoid placing impediments in the way of proposed new infrastructure and to allow competitive forces to determine the wisdom of expansions.

CONCLUDING COMMENTS

THE WA GOVERNMENT'S ECONOMIC DEVELOPMENT APPROACH

For a considerable number of years, successive Western Australian Governments have involved themselves closely in the State's major developments, viewing themselves as a partner rather than bodies that administer laws and allow others to pursue opportunities.  The basis of this interventionist approach in WA is a view that the State's vastness, its sparse population concentrated in the south-west, and the large size and dominance of its projects leave it ill-suited to government detachment from commercial decisions.

A key aspect of WA interventionism is that many projects proceed on the basis of specific State Agreements.  Originally, State Agreements were designed to facilitate development in remote areas where the legal regime established to cater for urban developments was inappropriate.

Although facilitation of major new proposals may have a role, governments should avoid tailoring laws to each new proposal as this brings about inconsistency, increases lobbying costs and raises the risk premiums that business require to contemplate new developments.  In the past, this interventionist approach has led to the WA Inc outcomes that corrupted the process of government and resulted in losses of hundreds of millions of dollars to the taxpayer.  An earlier Backgrounder ⁽⁸⁾ addressed the political decision-making environment in which the coal-based Collie power station was decided upon.  In that case politics were allowed to override economics and coal was favoured over gas for a new power station.

For all but the most unusual proposals, project-specific agreements should have little place in nations like Australia with clear laws and established legal traditions.  Moreover, far from facilitating development, in recent times, State Agreements have sometimes been used to thwart aspects of development that are not in accord with other Government policies.  One example of this is the conditions imposed on the Kingstream project at Geraldton which permit the building of a pipeline only as far as Geraldton, presumably to shield the existing pipelines from competition in the south-west.  Another example is the preferred position that Alinta has been given as a gas supplier to the Kingstream project.

RECENT ENERGY POLICY DEVELOPMENTS

It is a moot point whether the previous central planning approaches in WA accelerated worthwhile developments but, as in other States, the WA Government has now adopted a market-oriented policy which avoids subsidies to particular projects.  Consistent with this approach, the present Government has made some moves towards deregulating energy in the State but these remain tentative and framed within a highly prescriptive framework.

The disaggregating of the gas contract with the NW Shelf Joint Venture paves the way for an opening of the market.  This, the opening up of major Alinta and Western Power customers to competing supplies, the encouragement of new non-government-owned electricity generation, and a recent announcement by the Minister that the easement from the NW Shelf will be expanded and leased out to private sector operators, all set the stage for a liberalisation of the market structure.

Although the Government is seeking to move the State's energy and resource development policies on to a less regulated and privately-owned basis, energy policy in the State remains haunted by previous deals.  The most important of these concern gas, which is the key to WA's energy future.

Previous decisions of Governments with regard to gas have meant:

1. There is a monopoly pipeline funded by the taxpayer which appears to have been built (or financed) at excessive cost and which appears to be operationally more expensive than comparable pipelines.  A rival pipeline will force a reduction in its prices, offering benefits to customers but reducing its value to taxpayers.
2. The Government has signed contracts for gas supplies at prices that now appear to be above those that might be negotiated.  These prices will be forced down by the availability of a rival transport mode.  Again this is to the benefit of customers.  Any gas which is contracted at an inflexibly high price by Alinta will see rival suppliers in the market forcing the business to discount the price it requires, causing it to incur losses.  In the case of Western Power, a higher price for electricity reflecting excessive gas costs will encourage new generator entry and put downward pressure on Western Power's prices.
3. The contracts for gas were for excesive quantities and there is an inventory comprising a backlog of unused demand, which is, however, being reduced.

The Government is seeking to ensure that its previous decisions do not have an adverse effect on the taxpayer.  But if policies are followed that artificially ramp up the price of assets or prevent competition from pushing prices down, the taxpayer's gain is the customer's loss.  Increased prices for the existing pipeline and protection of the Alinta and Western Power gas contracts can only be engineered by denying users lower prices than would otherwise be available.

APPROPRIATE POLICY APPROACHES

Sunk costs and "stranded" assets which are greatly devalued by changed competition or technology environments are not unique to Western Australia.  The US has an estimated $202 billion of such assets in the electricity industry, almost half of which are nuclear. ⁽⁹⁾ These are assets which produce goods and services more expensively than alternative assets but which previously were sheltered from competition by government regulation.

The appropriate approach to such problems is to have the equity-owner carry the costs, unless the owner has incurred expenditures on the basis of government assurances, in which case the government must incur all or a proportion of the costs.  The shareholder is in the risk-taking business and is motivated by the prospects of high profits and avoidance of losses.  Where the government is the shareholder, the taxpayer will make these gains or losses (and the superiority of private enterprise partly stems from governments being ill-equipped to take on entrepreneurial roles).

The correct policy approach is to treat bygones as bygones and not to deny users lower prices.  If some of the sunk costs are to be recouped directly from customers rather than from shareholders/taxpayers, this is best achieved by means of a surcharge levied on all users (other than those that have contracted at a fixed price).  Such measures are applied in US jurisdictions and have been used in Victoria where the excess costs of the Loy Yang B power station are defrayed by a customer "uplift" payment of $2/MWh.  Measures like this are inferior to writing off the costs because the price levels are increased and some worthwhile usage is choked off, but they are preferable to denying the construction of a new facility.

Following the agreement by all Australian governments to the Hilmer-inspired reforms, the correct policy approach discussed above is also the approach adopted by governments.  Competition policy across Australia rejects preventing new investment and favouring existing investment.  The reforms, pursuant to such policy approaches, were estimated by the Industry Commission to bring real annual net gains in GDP of $23 billion. ⁽¹⁰⁾ The Commonwealth, in recognition that it gains a larger proportion of the tax "dividends" than State Governments, is to share $16 billion of this gain with the States over the next nine years, providing the States abide by their competition reform obligations.  Western Australia's share is about 10 per cent of the $16 billion.

ENDNOTES

1.  See Electricity 1996 International Benchmarking, Industry Commission, 1996

2.  Energy Western Australia, Office of Energy, June 1996.

3.  Although not recorded, Alcoa, as a result of its pivotal role in allowing the pipeline to be built, is thought to be charged a concessional rate at about $0.13 for the commodity charge and will cease to incur the reservation charge after 2005.

4.  EAPL Moomba-Wilton average tariffs are 87 cents/GJ for customers with an 80 per cent load factor;  PASA tariffs to Adelaide are 53 cents/GJ.

5.  The three inter-governmental agreements constituting the NCP Agreements are the Conduct Code Agreement;  the Competition Principles Agreement and the Agreement to Implement the National Competition Policy and Related Reforms.

6.  Prior to the experience of the England and Wales electricity market outcome, the Hirfindahl-Hirschman index had offered a rule of thumb which suggested four firms of similar size in a market would be ample for workable competition.  But the three large generation businesses in the England and Wales market (Powergen, National Power and British Electric) together with power from Scottish Power and Electricité  de France still resulted in market power.  The two smaller sources and British Electric were irrelevant to the price which was set by the mid-range cost thermals in Powergen and National Power.  At present, price wars in NSW electricity supply call for further refinement of the notion of what constitutes adequate competition.  In that State, competition between three government-owned generators has driven prices close to marginal costs for a period of over one year.

7.  This having been said, it must also be acknowledged that the Treasurer in both NSW and Victoria is also the energy minister.  However, in both States, policy was driven by a wish to increase competition -- even where, in the case of Victoria, this was to the detriment of revenue from asset sales.

8.  Harman F., "Gas, Coal and Politics:  Making Decisions About Power Stations", Backgrounder, Vol. 4, No. 3, 1992.

9.  Seiple C, "Stranded Investment:  the Other Side of The Story", Public Utilities Fortnightly, 15 March 1997, pages 10-11.

10.  Industry Commission, The Growth and Revenue Implications of Hilmer and Related Reforms, AGPS, Canberra 1995.

ACKNOWLEDGEMENTS

A number of people made useful comments upon an earlier version of this paper.  I should like to thank them all and, in particular, Dr Frank Harman of Murdoch University.  Naturally, responsibility for the final version is mine alone.