MOOMBA TO ADELAIDE NATURAL GAS PIPELINE (Moomba to Adelaide Pipeline System)
APPLICATION UNDER SECTIONS 1.24 AND 1.25 OF THE NATIONAL THIRD PARTY ACCESS CODE FOR NATURAL GAS PIPELINE SYSTEMS FOR REVOCATION OF COVERAGE
March 2005
Epic Energy South Australia Pty Ltd ACN 068 599 815 Level 8, 60 Collins Street Melbourne Victoria 3000 CONTACT: Stephen Livens TELEPHONE: (03) 8626 8414
MAPS APPLICATION FOR REVOCATION OF COVERAGE
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Table of Contents
1. FORMAL APPLICATION DETAILS...... 2
2. BACKGROUND INFORMATION...... 6 PIPELINE AND CONTRACTED CAPACITY – THE POSITION NOW AND IN THE FUTURE...... 6 HISTORICAL DEVELOPMENT OF MAPS ...... 7 OWNERSHIP AND OPERATION OF MAPS...... 9 3. MAJOR COMMERCIAL ISSUES...... 10 GAS SUPPLY ...... 10 GAS DEMAND ...... 10 GAS TRANSMISSION INFRASTRUCTURE ...... 11 SUPPLY AND DEMAND BALANCE...... 12 ELECTRICITY MARKET IMPACTS ON GAS DEMAND ...... 12 4. DEVELOPMENT AND INTRODUCTION OF THIRD PARTY ACCESS RIGHTS ON THE MAPS...... 14 OVERVIEW ...... 14 COMMITMENT TO INDUSTRY CODE OF CONDUCT...... 15 5. GROUNDS FOR REVOCATION – CRITERION (B)...... 18 DEFINITION OF SERVICES ...... 18 RECENT MOVES TO BROADEN THE DEFINITION OF SERVICES...... 19 RECOMMENDED APPLICATION OF REVISED DEFINITION...... 22 MAPS LATERAL PIPELINES ...... 24 CONCLUSIONS ON UNECONOMIC TO DUPLICATE...... 26 6. GROUNDS FOR REVOCATION - CRITERION (A)...... 28 APPROACH TO ASSESSING CRITERION (A) ...... 28 MARKET DEFINITION - UPSTREAM MARKET(S) ...... 30 MARKET DEFINITION - DOWNSTREAM MARKET(S)...... 31 MARKET DEFINITION CONCLUSIONS ...... 36 PROMOTION OF COMPETITION – APPROACH TO ASSESSING...... 37 PROMOTION OF COMPETITION - THE UPSTREAM MARKET...... 39 PROMOTION OF COMPETITION - THE DOWNSTREAM GAS SALES MARKET ALONG THE MAPS AND THE PORT PIRIE/WHYALLA LATERAL...... 40 PROMOTION OF COMPETITION - DOWNSTREAM GAS SALES MARKET IN SOUTH EAST AUSTRALIA ...... 42 PROMOTION OF COMPETITION - DOWNSTREAM ELECTRICITY SALES MARKET ...... 44 7. GROUNDS FOR REVOCATION - CRITERION (C)...... 46
8. GROUNDS FOR REVOCATION - CRITERION (D)...... 47
10. GLOSSARY...... 50
CONFIDENTIAL MAPS...... 53
ENERGY MARKET ANALYSIS...... 55
APPLICATION OF THE HYPOTHETICAL NEW ENTRANT TEST...... 77
WORKABLE COMPETITION IN THE DUOPOLY AIRLINE MARKET ...... 84
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1. Formal Application Details
1.1 Applicant’s name and contact details
Applicant’s name:
Epic Energy South Australia Pty Ltd (“Epic Energy”) (ACN 068 599 815)
Contact details for Epic Energy:
Manager, Regulation Risk & Insurance Epic Energy Level 8, 60 Collins Street, Melbourne Victoria 3000
Phone: (03) 8626 8414 Fax: (03) 8626 8454
1.2 Applicant’s address for the delivery of documents
Documents should be sent by mail and (where possible) e-mail to the following addresses:
Mailing address:
Epic Energy Level 8, 60 Collins Street, Melbourne Victoria 3000
Email: [email protected]
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1.3 Description of the Covered Pipeline
The Covered Pipeline comprises the following parts of the Moomba to Adelaide Pipeline System (the “MAPS”):
(a) the Covered Pipeline as described in Schedule A of the Code (reproduced below) as follows:
Pipeline Location/Route Operator Length (km) Pipe Regulator Licence diameter (mm) SA:PL1 Moomba to Adelaide Epic ACCC Pipeline System Energy Pty Ltd * Moomba to Adelaide 781 559 Pipeline Angaston Lateral 38.7 219 Taperoo Lateral 1.2 323 Dry Creek Lateral 1.3 323 Peterborough Lateral 1.9 89 Nurioopta Lateral 1.6 114 Burra Lateral 15 89 Port Pirie Lateral 77.8 168 Mintaro Lateral 0.3 219 Wasleys to Torrens 42 508 Island Loop Whyalla Lateral 87.7 219 Port Bonython Lateral 5.5 114 Tarac 0.4 89 Port Douglas Lateral 11.5 114 Osborne Lateral 1.3 273 *Epic Energy Pty Ltd has never been the operator of the MAPS – the correct operator was, and remains, Epic Energy Corporate Shared Services Pty Ltd (“EECSS”).
(b) the following enhancements to the pipeline system that have been carried out since 11 November 1997:
− the upgrading of all of the Solar Centaur compressor units in 1998 to Solar Taurus units; and
− the upgrading of the Alison compressor units in 1998 at CS2 (one unit) and CS4 (both units).
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For the avoidance of doubt, the Covered Pipeline does not include the following parts of the MAPS (“uncovered pipeline”)
• the New Facilities or expansion in capacity of the pipeline effected pursuant to the Pelican Point Power Extension/Expansion which in 1999, 2000 and 2001 involved:
− the upgrade of the remaining Allison compressor units (at CS1, CS3, CS5 and CS6);
− 34 kilometres of looping of the MAPS mainline at various locations between CS1 and CS5;
− the construction of a 1.7km lateral from the mainline to the location of the power station known as the Pelican Point Power Station together with a meter station at the downstream end of the lateral; and
− the installation of an additional compressor unit at Wasleys to provide additional pressure service to the mainline loop of the MAPS;
• the 10.2km x 4” Amcor lateral and meter station; • the 0.12km x 6” Quarantine Power Station lateral and meter station; and • the 0.72km x 8” Hallet Power Station lateral and meter station.
A confidential map showing the physical location of the MAPS is contained in Attachment A. For security reasons, a copy of this map will only be made available to bona fide access seekers, the NCC, its staff and the Minister.
1.4 Name of the Covered Pipeline operator and owner
The MAPS is owned by Epic Energy.
The MAPS is operated by EECSS under a services agreement with Epic Energy.
Epic Energy is the Service Provider under the Code.
1.5 Whether the applicant is seeking revocation of coverage of all or part of the covered pipeline
Epic Energy is seeking revocation of coverage of the entire Covered Pipeline, and any further extensions or expansions as might be described under sections 1.40 and 1.41 of the Code.
1.6 Reason for seeking revocation of coverage of the pipeline
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Epic Energy is seeking revocation of coverage because it submits that the NCC and the Minister can not be satisfied of all of the matters set out in paragraphs (a), (b) and (d) of section 1.9 of the Code.
A detailed substantiation is set out in the following sections of this application.
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2. Background information
2.1 This section of the submission briefly outlines Epic Energy’s reasons for making the revocation application for the Covered Pipeline and provides supporting background material.
2.2 The following background information is intended to provide a relevant context for the consideration of each of the coverage criteria, which are individually addressed in later sections of this submission.
Pipeline and contracted capacity – the position now and in the future 2.3 The MAPS was originally constructed in 1969 by the South Australian Government and was operated by the Pipelines Authority of South Australia (PASA) until 1995. Since then, its capacity has been enhanced in various stages so that the maximum capacity of the MAPS is now 418 TJ/day. The maximum capacity of the Covered Pipeline is, however, only 393 TJ/day.
2.4 Allowing for operational factors such as the impact of summer temperatures, the firm capacity of the Covered Pipeline as configured in December 2004 is 323TJ/day and of the system including the uncovered portion is 348TJ/day.
2.5 More details as to how and when the capacity of the MAPS was expanded over time are set out in paragraph 2.15 of this application.
2.6 These expansions were carried out in order to meet the required demand of shippers1 which resulted in long term transportation contracts being signed by shippers.
2.7 Until the commissioning of the SEA Gas pipeline linking Victoria and South Australia in January 2004, the MAPS was the only transmission pipeline transporting gas to the South Australian market. At that time the MAPS firm capacity was fully contracted. However, the entry of the SEA Gas pipeline has effectively doubled the gas transportation capacity into South Australia and the share of gas transportation contracts held by the MAPS is forecast to decline dramatically upon expiration of current contracts. Throughput on the MAPS has already declined since commissioning of the SEA Gas pipeline.
2.8 The majority of these transportation contracts that supported the expansion of the MAPS to its current capacity however, come to an end in 2005. At that time, the Service Provider will have significant spare capacity on the MAPS.
2.9 While Epic Energy believes that it will be able to secure transportation contracts for the period following 2005, Epic Energy’s own forecasts and that of
1 The most recent expansion of the pipeline system (known as the “Pelican Point Power Expansion” see paragraph 1.3) carried out in 2000 and 2001, was done to meet the contractual obligations owed to one shipper. However, this is not part of the Covered Pipeline.
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independent experts conclude that there will be a significant period following 2005 when the MAPS capacity will be significantly under utilised.
2.10 In Hastings’ Product Disclosure Statement for the Hastings Diversified Utilities Fund, Hastings forecast that MAPS contracted volumes would decline from 418 TJ/d in 2005 to 194 TJ/d in 2006.2
2.11 There are a number of reasons for this. These will be outlined in more detail later in this application. However, in summary they include:
(i) the commissioning of a second transmission pipeline (the SEA Gas pipeline) into the main end-market served by the MAPS;
(ii) competing demand from various downstream markets for the remaining Cooper Basin gas reserves;
(iii) increased competition from alternative energy sources such as electricity interconnectors; and
(iv) the statutory regime that applied to the pipeline until 2003 and the impact that this regime and its application had on the Service Provider’s ability to clear a “bottleneck” in the allocation of capacity for the period following 2005. This bottleneck was created by shippers.
2.12 Epic Energy is therefore incentivised to offer innovative, market based price and service offerings to customers in order to establish contracts to replace the expected reduction in contracted capacity and throughput following 2005.
2.13 Accordingly, based on the submissions outlined in this and subsequent sections of the application, Epic Energy submits that the NCC and the Minister could not be satisfied of one or more of the matters set out in paragraphs (a), (b) and (d) of Section 1.9 of the Code and, therefore, the NCC must recommend, and the Minister must decide, that coverage of the Covered Pipeline be revoked to the extent described in this application.
Historical development of MAPS 2.14 Initially, it is important to understand how the development of the capacity of the MAPS has evolved over time.
2.15 A chronology of the development of the MAPS is set out in the table below:
2 Hastings Diversified Utilities Fund Product Disclosure Statement p4
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Date Description 1969 • the MAP was constructed and commissioned as a free flowing pipeline from Moomba to Torrens Island 1977 • installation of Solar Centaur Compressors at CS1, 2, 3, 5 and 6 1979 • installation of Alison gas turbines at CS1, 2, 3, 4(2 off), CS5 and CS6 • installation of two Solar Centaur machines at CS7 1986 • construction of a 42km (20”) loop line between Wasleys and Torrens Island 1990 • installation of a compressor unit at Whyte Yarcowie 1996 • construction of the 1.2km x 10” Osborne lateral and meter station (note the last 0.2km has 8” diameter) 1998 • replacement of all of the original Solar Centaur units at CS1, CS2, CS3, CS5 and CS6 to Solar Taurus units • the upgrading of the power of the Alison engines at CS2, and both units at CS4 1999 • construction of the 1.7km x 14” Pelican Point lateral and meter station 2000 • Upgrading the power of the Alisons units at CS1, CS3, CS5 and CS6 • construction of 34 kilometres of 24” loop in four sections downstream of CS1, CS2, CS3 and CS4 • Installation of a reciprocating compressor unit at Wasleys to provide additional pressure service to the loop. 2001 • construction of 10.2km x 4” Amcor lateral and meter station • construction of 0.12km x 6” Quarantine Power Station lateral and meter station • construction of 0.72km x 8” Hallet Power Station lateral and meter station • upgrading of the power of one Solar Centaur unit at CS7
2.16 In 1977, the original free flowing MAPS from Moomba to Torrens Island Power Station was compressed with the installation of Solar Centaur Compressors at CS1, 2, 3, 5 and 6.
2.17 In 1979, the MAPS underwent a second enhancement with the installation of Alison gas turbines at CS1, 2, 3, 4 (2 of), CS5 and CS6. In addition, CS7 was also developed with the installation of 2 Solar Centaur machines.
2.18 The MAPS remained in this configuration until 1986 when a loop was constructed between Wasleys and Torrens Island. The purpose of the loop was two-fold, one to provide an alternative supply of gas from broad rural to metropolitan Adelaide as the original pipeline section was de-rated to 60% and, secondly, to provide higher pressure supply to the industrial areas and power generators being constructed in Adelaide.
2.19 In 1998, with additional loads required on the MAPS, a third enhancement was undertaken with the upgrading of all the original Solar Centaur machines to Solar Taurus machines together with the upgrading of some of the Alison engines.
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2.20 In 2000, a further capacity enhancement was carried out with the upgrade of the remaining Alison engines and looping of 34 kilometres of the MAPS between CS1 and CS4. In addition a compressor was installed at Wasleys to provide additional pressure service to the loop.
2.21 The MAPS, as currently configured, is a 1,185 km system of pipelines3 providing a link within the integrated South East Australian energy market, including servicing Moomba, Adelaide and regional centres throughout South Australia.
2.22 The MAPS is comprised of a 781 kilometre trunk line between Moomba and Adelaide with a diameter of between 559 mm and 600 mm, two main lateral pipelines (the Whyalla and Port Pirie lateral and the Angaston lateral) and a series of customer specific laterals.
2.23 The maximum capacity of the covered elements of the MAPS (with compression but excluding the Pelican Point Power Station uncovered expansion discussed in paragraph 1.3) is 393TJ/day. Inclusion of the Pelican Point Power Station expansion increases maximum capacity of the system to approximately 418 TJ/day. Allowing for operational factors such as the impact of summer temperatures, the firm capacity of the Covered Pipeline as configured in December 2004 is 323TJ/day and of the system including the uncovered portion is 348TJ/day.
Ownership and Operation of MAPS 2.24 In August 1994, US company Tenneco Gas, a subsidiary of Tenneco Inc, established Tenneco Gas Australia to invest in opportunities within the Australian gas industry. In July 1995, Tenneco Gas Australia acquired the operations and assets of PASA. In November 1995, the company changed its name to Tenneco Energy Australia after Tenneco Gas in the US changed its name to Tenneco Energy. In March 1996, Tenneco Inc announced its plan to sell off Tenneco Energy. The sale took place in December 1996 with US company El Paso Energy acquiring Tenneco Energy.
2.25 Epic Energy was created when El Paso Energy retained 30 percent of Tenneco Energy's Australian operations with the remaining 70 percent acquired by CNG International (30%); Allgas Energy (10%); AMP Investments (10%); Axiom Funds Management (10%) and Hastings Funds Management Limited (“Hastings”) (10%).
2.26 In June 2004 Hastings, through its subsidiary, HUT 3 Pty Ltd (now Epic Energy Holdings Pty Ltd), acquired ownership of Epic Energy and its assets excluding the Dampier to Bunbury Natural Gas Pipeline but including the MAPS and various other pipelines.
2.27 The assets owned by Epic Energy Holdings Pty Ltd (including the MAPS), were rolled into a fund called the Hastings Diversified Utilities Fund, and in December 2004 this Fund was listed on the ASX after a successful IPO.
3 Hastings Diversified Utilities Fund (HDUF), Product Disclosure Statement 2004, page 6.
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3. Major Commercial Issues
3.1 The Australian gas market has changed rapidly over recent years with significant investment in exploration and associated processing and transmission infrastructure. Over the last 25 years natural gas consumption is estimated to have increased at an annual rate of nearly 6.9% with total Australian consumption currently estimated to be around 1,000 PJ per annum representing around 19% of Australia’s primary energy consumption. This proportion is forecast to increase to 24% or more than 1,800 PJ by 2019-20.4
3.2 These changes have the potential to significantly alter competitive dynamics and as such, Epic Energy has undertaken a comprehensive review of currently available information on factors likely to impact on gas supply and demand. This analysis is provided as Attachment B. A brief summary of key findings is presented below.
Gas Supply 3.3 Australia’s main sources of gas supply are located in north and north-west Australia. However, there remain significant reserves in central and eastern Australia (Table 1), and it is these reserves that have supported the current development of the gas market.
Table 1 Eastern Australian gas reserves (PJ) 2002 Non- Production Basin Commercial commercial Total 2000/01 Adavale 14 – 14 1 Bass – 376 376 – Bowen–Surat 107 122 229 24 Cooper–Eromanga 3,503 913 4,416 211 Gippsland 5,974 2,055 8,029 239 Otway 30 1,670 1,700 8 Total 9,628 5,136 14,764 483
Source: Dickson and Noble 2003. Eastern Australia’s Gas Supply and Demand Balance. APPEA Journal 2003 p 137
Gas Demand 3.4 Information on natural gas consumption by region or locality exhibits a high degree of variability although aggregate figures are expected to be relatively reliable. Estimates of South Australian consumption have exhibited the greatest variability of any of the states and Epic Energy believes that the most appropriate base figure for South Australian demand is provided by the MAPS throughput as
4 ABARE August 2004. Australian Energy national and state projections to 2019-20. p23
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reported to the South Australian Minister for Energy plus the gas transported on the South East Pipeline (4 PJ/yr) and fuel gas on the MAPS (1 PJ/yr).
3.5 In 2003, the amount reported to the Minister was some 91.5 PJ having decreased from around 100 PJ in each of the two preceding years. The main reasons for this reduction in throughput are:
(a) as a result commissioning of the Murraylink interconnector; and
(b) increased utilisation of the Heywood interconnector,
with electricity imports to South Australia increasing by some 1.4 TWh or some 11% of total South Australian electricity demand in 2003. This increase in imported electricity was matched by a decrease in South Australian gas fired generation as a proportion of total consumption from 56% to 45%.5
3.6 Forecast growth in South Australia’s natural gas demand has been estimated by ABARE at slightly less than 50% over the fifteen year period from 2004/05 to 2019/20. This is an increase from approximately 103 PJ in 2004/05 to 153 PJ in 2019/20.
Gas Transmission Infrastructure 3.7 South-east Australia now has an intimately interlinked network of high pressure gas transmission pipelines that currently exhibits significant spare capacity with additional capacity available through relatively low cost expansion of existing assets. A summary of major eastern Australian pipelines and potential capacity is provided in Table 2.
Table 2 Estimated pipeline capacity (fully compressed) Fully Compressed Capacity at Capacity 75% load Pipeline (TJ/day) factor Moomba to Sydney 795 596 Moomba to Adelaide 418 313 SEA Gas 411 308 EGP 301 226 SWQP 301 226 Roma to Brisbane 137 103 QGP 142 107 Carpentaria 137 103 Interconnect 52 39 TGP 178 134
5 www.nemmco.com.au
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Supply and Demand Balance 3.8 ABARE have undertaken detailed modelling of Australia’s gas supply and demand balance out to 2019/20. This modelling highlighted a progressive change in the source of gas as demand continues to increase in eastern Australia, with a source of northern gas (possibly from PNG or Timor Sea), required to be delivered to Moomba by around 2012/13.6
3.9 Correlating ABARE’s demand forecast with existing (developable) pipeline capacity indicates that the South Australian market is likely to continue to be faced with excess pipeline capacity until at least 2020, even allowing for the possible impact of northern gas delivered via Moomba.
Electricity Market impacts on gas demand 3.10 As noted in paragraph 3.5, gas demand in South Australia has exhibited significant variability associated with the level of electricity supplied by gas fired generators in South Australia. The proportion of South Australian electricity demand satisfied by different sources is summarised in Table 3. Over the period from 2000 to 2003, total electricity consumption was relatively stable, with coal fired generation satisfying roughly between 32% and 35% of total demand. This table highlights that the chief variance in supply was between imports and gas fired supply with imports increasing by over 10% between 2002 and 2003.
Table 3 Proportion of SA electricity consumption by generation source Consumption Year TWh Coal Import Gas 2000 12.8 35.4% 23.6% 41.0% 2001 12.9 33.7% 12.8% 53.5% 2002 12.9 32.4% 11.4% 56.1% 2003 12.8 32.3% 22.5% 45.2%
3.11 This change reflects the recent augmentation of the interconnection capacity between Victoria and South Australia, with NEMMCO stating that currently, it treats Victoria and South Australia as a single region due to the fact that7:
• supply-demand balance is dependent on the network capability into Victoria from Snowy and Tasmania (post Basslink commissioning);
• Victoria to South Australia interconnectors do not constrain the flows in or out of South Australia during high demand periods; and
• regions are subject to similar weather patterns.
6 Dickson and Noble 2003. Eastern Australia’s Gas Supply and Demand Balance. APPEA Journal 2003 p 142 7 NEMMCO 2004 Statement of Opportunities Executive Summary p.3
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3.12 As there is no binding network constraint between South Australia and Victoria, any price separation between the South Australian average price and the Victorian average price will be a function of inter regional transmission loss factors. That is, the prices faced by South Australian generators are constrained by the prevailing spot price in the NEM.
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4. Development and introduction of third party access rights on the MAPS
Overview 4.1 Most of the existing contractual rights to capacity on the Covered Pipeline arise from the contracts established as part of the unbundling process for the previous combined gas and haulage arrangements between the former PASA and its customers. These new contracts were signed in late June 1995 immediately prior to the privatisation of the MAPS.
4.2 On 1 April 1999, Epic Energy submitted its proposed Access Arrangement for the Covered Pipeline as required under the National Third Party Access Code for Natural Gas Pipeline Systems. At the time, the Covered Pipeline was effectively fully contracted with respect to available firm capacity. The ACCC drafted and approved its own Access Arrangement on 31 July 2002. However, on 10 December 2003, this Access Arrangement was varied by order of the Australian Competition Tribunal, with these variations taking effect immediately.
4.3 A proposed revised Access Arrangement is due to be submitted by 1 July 2005 and the revisions are due to commence from 1 January 2006.
4.4 While the MAPS remains fully contracted up until this time, significant capacity is expected to be available from 1 January 2006 due to the expiry of current contracts.
4.5 It is Epic Energy’s current intention that the proposed revised Access Arrangement will be based on the reduced contracted capacity expected from 2006 and as such, the revised reference tariff to be set pursuant to Section 8 of the Code (based on the Cost of Service methodology) is expected to significantly increase compared to the reference tariff set under the current Access Arrangement.
4.6 This increase is a reflection of the application of the efficient cost, building block approach adopted by the ACCC and the fact that the expected 50% reduction in contracted capacity will have only a minor impact on efficient building block costs, with the result that reference tariffs based on a per GJ charge will be much higher than would have been the case had the MAPS remained fully contracted. Indeed, applying this approach in circumstances where there was no change to the costs of providing the service would see reference tariffs increase proportionally to the decrease in contracted capacity – implying a significantly higher reference tariff compared to the current level of around $0.49/GJ.
4.7 While the actual increase is likely to be less (partly due to additional depreciation of the MAPS assets), Epic Energy still considers that any reference tariff derived by application of the Code will be significantly above the market price at which MAPS capacity will be able to be contracted. As such, a reference tariff established under the Code will be unlikely to have any meaningful information content for prospective users.
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4.8 Epic Energy has also undertaken an assessment of the price required to support a new entrant in the market and considers that this new entrant price is likely to be similar to the revised reference tariff. Epic Energy has estimated the likely price required by an efficient new entrant to be between $0.85/GJ and $0.92/GJ where the new entrant was able to contract volumes similar to the post 2006 volumes attributed to Epic Energy (see Attachment C).
4.9 However, both the efficient new entrant price and revised reference tariff are likely to be above the market price. One indication of the possible upper limit for the market price is given by the SEA Gas offer of a $0.63/GJ tariff ($2004) for firm capacity listed on its website. However, this offer expired on 24 December 2004 and Epic Energy is unaware of any new terms that SEA Gas is likely to offer. Nevertheless, the competitive tension between the SEA Gas pipeline and MAPS is certain to ensure that both parties use all possible commercial strategies, including pricing, to capture marginal customers.
Commitment to Industry Code of Conduct 4.10 Looking to the future, the critical issue that arises in the face of the potential revocation of the MAPS is how access would be provided by Epic Energy on an unregulated pipeline. This goes to the heart of the issue raised by the ACT in the Duke Eastern Gas Pipeline decision (the EGP Decision) "The enquiry is as to the future with coverage and without coverage".8 The onus is on the affirmative demonstration that the "future with coverage" will, or is likely to lead to circumstances which will produce positive benefits (in terms of the coverage criteria), relative to the situation which exists without coverage.
4.11 As noted in paragraph 4.9, SEA Gas has indicated a willingness to provide transport for around $0.63/GJ, while the current reference tariff on the MAPS is approximately $0.49/GJ. In the NCC’s Final Recommendation on the MSP revocation application, the NCC estimated the well head price per GJ of gas at around $2.60 (ex Moomba) and between $2.60 and $2.80 (ex Longford). By comparison, Epic Energy understands that the 2005 well head prices are around $3.10 for Otway Basin gas, $3.10 to $3.15 for Copper Basin gas and $3.05 to $3.10 for gas ex Longford. That is, while well head prices have increased in both nominal and real terms, the spread of prices appears to have narrowed as the gas transmission pipeline network has become increasingly interconnected and inter-basin competition has intensified.
4.12 In addition to the above market pricing constraints, and in the context of the MAPS, where access has previously been offered on terms and conditions detailed in the regulated Access Arrangement, it is the intention of Epic Energy to move to the development of commercial, market responsive, service offerings that potentially better match user requirements than the Access Arrangement. These service offerings will be developed and communicated to users and potential users in a manner consistent with the Australian Pipeline Industry Association’s (APIA’s) Industry Code of Conduct. This Code of Conduct is consistent with that developed by Duke Energy International (“Duke”) for
8 Duke Eastern Gas Pipeline Pty Ltd [2001] ACompT2, Australian Competition Tribunal, 4 May 2001,, paragraph 75, page 20.
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application to its unregulated pipeline assets (the Eastern Gas Pipeline (“EGP”) and Tasmanian Gas Pipeline “TGP”) and subsequently applied by Alinta to these assets upon Alinta’s purchase of the Duke assets. As such, this Code of Conduct has been in operation for a number of years and has provided a sound basis to support the increasing competitiveness of the Australian gas market.
4.13 In its submission to the Productivity Commission review of the National Gas Access Regime, APIA outlined the reasons for developing the Code of Conduct as:9
The purpose of this Code of Conduct is to set out a behavioural framework of guiding principles that support non-regulated, market responsive access to uncontracted spare capacity in gas transmission pipelines not covered under the Code. Because providing access and selling capacity for unregulated pipelines is necessary to success, such practices are already substantially in place in different forms developed by each pipeline. Notwithstanding the presence of such individual approaches to ensuring access, the industry is keen to see the national gas market develop and recognises the benefits of a uniform approach in facilitating its development. A uniform voluntary approach also has the benefit of providing policy makers and access seekers with confidence without the cost of associated regulation.
4.14 The eight core Code of Conduct principles are the commitment to:
• developing market-responsive pipeline services; • the use of non-discriminatory tariffs; • public disclosure of dealings with affiliates; • public disclosure of key contract details; • protection of confidential information; • facilitate capacity trading; • performing independent external audits of compliance with the principles; and • binding independent dispute resolution process.
4.15 Epic Energy participated in the development of the Code of Conduct and separately outlined its intention to adopt a comprehensive version of the Code of Conduct in its submission to the Productivity Commission which would be consistent with the principles outlined in APIA’s Code of Conduct.10
4.16 In practice, application of the above Code of Conduct will mean that Epic Energy will be committed to operating the MAPS as an open access pipeline, to develop new service offerings aimed at better servicing users and, in turn, offer the same
9 APIA 12 September 2003 Submission to the Productivity Commission Review of the National Gas Access Regime. p70 10 Epic Energy September 2003. Submission in Response to Issues Paper para 8.30
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terms and conditions to any other party that wishes the same service. Further, the Code of Conduct will ensure that key terms and conditions will be publicly disclosed ensuring that all potential users can be certain that they will not be discriminated against while still ensuring that confidential information will only be used for the purpose for which it was provided. Epic Energy believes that the presence of the Code of Conduct will ensure that coverage of the MAPS will not produce positive benefits (in terms of the coverage criteria), relative to the situation which will exist without coverage.
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5. Grounds for revocation – Criterion (b)
5.1 Given the changed market conditions faced by the MAPS with the entry of SEA Gas into the Adelaide market, together with the emergence of an increasingly competitive south eastern Australian gas market, Epic Energy no longer considers that the Covered Pipeline satisfies the coverage criteria under section 1.9 of the Code. The following sections address each of the coverage criteria using the NCC’s standard approach of first addressing criterion (b), then (a), (c) and (d).
Definition of services 5.2 Criterion (b) is satisfied where it can be shown:
that it would be uneconomic for anyone to develop another Pipeline to provide the Services provided by means of the Pipeline
5.3 The key issue in establishing whether it is economic to duplicate a pipeline is the definition of the “services” provided by means of the pipeline. For the purposes of considering criterion (b), the Covered Pipeline may be thought of as being comprised of a number of separate pipeline systems, these are the main Moomba to Adelaide pipeline, and the Port Pirie/Whyalla and Angaston laterals.
5.4 In Epic Energy’s view, the relevant services on the MAPS fall into two categories:
• transportation of gas within the integrated south eastern Australian gas market; and
• transportation of gas to markets along the MAPS (north of the Angaston lateral) and along the Whyalla lateral.
5.5 Epic Energy believes this definition reflects the reality of the now fully integrated gas transmission network within south-east Australia.
5.6 This definition varies from that historically adopted by the NCC, namely, a point to point definition – for example, most recently with the Goldfields Gas Pipeline (“GGP”) Revocation Application, where GGT argued the appropriate definition of service was:
…the transportation of gas for the main purpose of generating electricity as part of an interconnected Western Australian energy transmission network (illustrated in map 3 of appendix 1 to the application). (GGT 2003, p. 60)
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5.7 The NCC rejected this definition and adopted the following definition:11
The Council considers that the service provided by the GGP is a gas transportation service from the DBNGP Compressor Station One at Yarraloola to Kalgoorlie and all points in between, via the East Pilbara and North East Goldfields regions of Western Australia.
5.8 The NCC argued that this definition is consistent with the approach adopted by the Australian Competition Tribunal (Tribunal) in the Duke case where the Tribunal decided that the “service” provided by means of the EGP was a haulage service for the transport of gas between one point on the pipeline and another.
Recent moves to broaden the definition of services 5.9 This narrow interpretation of criterion (b) serves to place increased (and undue) reliance on criterion (a) to ensure that coverage is restricted to those pipelines with substantial and enduring market power. This problem has been recognised by the Productivity Commission. For example, in its report on the Review of the National Access Regime (the Review), the Productivity Commission (the Commission) discussed the implications of the EGP Decision and in particular, the point to point definition of the service provided by the pipeline in the context of the uneconomic to duplicate test. The Commission noted that:12
It is apparent from the EGP decision that the existence of close substitutes for a service provided by an essential facility – at least for gas pipelines – is not necessarily sufficient to rule out declaration in terms of criterion (b).
5.10 The Commission went on to indicate that under the Tribunal’s interpretation the role of criterion (b) was effectively limited to operating as a screening device for natural monopoly technologies, that is, criterion (b) was the first step in a two step process with criterion (a) then relied upon to assess the scope for close substitutes that may limit market power. The Commission felt that this two stage process could only work with significant strengthening of criterion (a):13
…it is essential that criterion (a) only be met where the facility in question can exercise substantial and enduring market power.
5.11 The fact that the uneconomic to duplicate test has tended to be so narrowly interpreted and therefore placed so much reliance on criterion (a) in terms of ensuring that declaration was not unnecessarily applied, led the Commission (in its review of the Code) to make a cautionary statement:
11 National Competition Council, November 2003. Application for revocation of coverage of the Goldfields Gas Pipeline under the National Gas Access Regime. Final Recommendation. Para.4.15 12 Productivity Commission, 2001. Review of the National Access Regime p.180 13 Productivity Commission, 2001. Review of the National Access Regime p.182
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…to the extent that the existence of substitute services is not dealt with under criterion (b), it is imperative that it is assessed effectively under criterion (a). If this were not the case, the key question of the market power related to natural monopoly would not be properly addressed.
5.12 The Commission went on to suggest that criterion (a) should be modified to include the word “substantial”. That is, that access would promote a substantial increase in competition. While the Government in its Final Response (dated 20 February 2004) to the Commission’s report accepted most of the Commission’s recommendations, the inclusion of the word “substantial” in criterion (a) was rejected and instead the Government proposed use of the word “material” that is, a material increase in competition.
5.13 Unfortunately, neither changes to the Part IIIA declaration criteria or the Code coverage criteria have yet been implemented. The Commonwealth Government indicated that it would introduce into Parliament the legislative changes to give effect to the final response to the Part IIIA review. It also indicated that the recommendations of the Code review were to be referred to the Ministerial Council on Energy (MCE) for action. At the time of preparing this application, the MCE had not responded to the Review’s recommendations although its latest timetable indicates that changes to the Code are to be finalised by the end of 2005.
5.14 Given the acknowledgement of the problems with the current interpretation of criterion (b) it is suggested that caution should be exercised in applying too narrow an interpretation to the uneconomic to duplicate criterion.
5.15 Further, it is clear that the gas transportation network has continued to evolve since the EGP Decision. This has led to the situation where an alternative view of the appropriate definition of service has been developed by the Hon Ian Macfarlane, MP, Minister for Industry, Tourism and Resources (in his role as a relevant Minister for assessing an application for revocation of coverage under the Code). This alternative view was expressed in his Decision on revocation of the MSP.14
While both the Interconnect and EGP emanate from different starting points, and therefore cannot be considered to provide transportation services out of Moomba, they do provide alternative means of delivering gas into the Sydney and ACT downstream gas markets, and in the case of the Interconnect to regional NSW markets. The extent to which they are part of a more integrated pipeline network that provides alternative links between Moomba and these various downstream markets, deserves consideration.
5.16 That is, the Minister acknowledged the need to broaden the definition of service to better reflect the reality of Australia’s rapidly developing gas transmission
14 Applications for Revocation of Coverage on Certain Portions of the Moomba to Sydney Pipeline System. Statement of Reasons 19 November 2003. para 20
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network. In particular, to move away from a point to point definition in order to reflect the availability of alternative transport options. The Minister went on to note at (para 22):
The gas transmission system in south-east Australia has now become a more integrated pipeline network. Transportation services to any given location around this network, either upstream or downstream, may be offered through a variety of means and by a variety of transmission service providers. As a consequence, physical capacity constraints along a single pipeline are unlikely to be a determining factor of gas supply, at least in the medium term.
5.17 The Minister summarised his approach in para 81:
(a) insistence upon physical duplication or a single point-to-point transportation service is not appropriate for an increasingly integrated gas pipeline network;
(b) considerations relevant to a pipeline being progressively exposed to network competition must be taken into account;
(c) it has been economic to develop other gas pipelines such as the Eastern Gas Pipeline, the SEA Gas pipeline as well as the Victorian Gas Hub in competition with the MSP Mainline. The present lack of technical interconnection is not a decisive factor, given the committed investments in place;
(d) the MAPS and proposed Ballera to Moomba pipelines offer alternative means of gas transmission out of Moomba in competition with the MSP Mainline to NSW;
(e) the SEA Gas pipeline, due for completion in 2004, will alleviate existing constraints on the Moomba to Adelaide Pipeline;
(f) as part of this integrated network, other pipeline owners and operators can be expected to further develop their pipelines to provide a wide range of services in competition with those currently provided by the MSP Mainline;
(g) there are at least two alternative means for downstream gas users contracting gas pipeline services to Sydney via the Interconnect and Eastern Gas Pipeline, including for physical swaps and back haul arrangements;
(h) both upstream and downstream gas transmission services between Moomba and Sydney are capable of being provided on a competitive basis by this integrated pipeline network, provided ownership considerations are not an issue ; and
(i) these competitive arrangements can be achieved within the timeframe of 10-15 years adopted by the Tribunal for considering whether the EGP was likely to remain a natural monopoly in output terms.
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5.18 In making these observations the Minister substantially broadened the interpretation of services away from the point to point approach adopted by the Tribunal in the EGP Decision. The Minister did so in recognition of the significant gas market development after the EGP Decision.
5.19 The Minister also concluded that at least three independent gas transmission systems at each major uptake and off take seem to be the minimum necessary for effective competition (para 52):
… This recognises the market power concerns of either single or duplicate pipelines, concerns about parallel pricing of transmission services or the maintenance of artificially high or low prices, and the need for separate and arms length commercial and ownership arrangements. Desirably, this should take the form of multiple shippers being able to contract independently along each of these pipelines.
5.20 It is considered that while the Minister’s approach significantly advances the concept of service definition by acknowledging the interconnected nature of the transmission pipeline system in eastern Australia, its reliance on three independent systems may understate the ability to deliver effective competition with less than three independent competing firms.
5.21 One reason to consider that a minimum of three service providers is unnecessarily restrictive is the fact that the size of the Australian domestic economy is relatively small by international standards with a GDP in USD terms in 2003 of around $520 billion which is less than one twentieth the size of the US economy.15 This is often used as a basis to argue that Australia cannot support multiple competitors in capital intensive industries where size is a prerequisite.
5.22 Another reason is that, simply because there may only be a small number of competing firms does not mean that such markets will not deliver effective competition with all of the concomitant economic benefits associated with competitive markets.
5.23 Indeed, the threat of entry may well be sufficient to ensure no misuse of market power even with only a single service provider and there is certainly ample evidence that two service providers are sufficient to ensure workable competition as witnessed in other sectors such as the airline industry. Evidence of the effectiveness of the competition within the deregulated airline industry where there are only two competitors is discussed in Attachment D.
Recommended application of revised definition 5.24 Despite the fact that Epic Energy submits there may not be a need to have three independent pipelines to create effective competition, Epic Energy nonetheless notes that in the case of the MAPS there are at least 3 competing pipelines. In
15 World Bank, September 2004, World Development Indicators database
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his Statement of Reasons, Minister McFarlane clearly acknowledges the common problem in assessing coverage, namely the incorrect focus on the monopoly characteristics of the physical infrastructure rather than focusing on whether the services are being provided in a monopoly manner (para 10). When the focus is correctly placed onto the nature of the provision of services, then Minister McFarlane’s threshold for three independent systems is satisfied for the MAPS mainline.
5.25 That is, gas producers at Moomba (the dependent upstream market) have the MAPS, MSP and the raw gas pipeline between the Ballera and Moomba gas plants (as noted by the Minister in the MSP revocation decision). The Adelaide component of the downstream eastern Australian gas market, even ignoring a broader energy market argument, is serviced by the MAPS and SEA Gas. Or more correctly, pipeline services may be sought from Epic Energy on the MAPS, or one of the three SEA Gas partners (International Power, Origin Energy and TXU Australia). That is, the ownership and contracting structure on the SEA Gas pipeline provides three virtual pipelines in itself, as noted by Minister McFarlane (para 112):
…Such services may be provided either by physically distinct gas pipelines or, using the SEA Gas pipeline as an example, by quite distinct ownership and contractual arrangements which effectively amount to separate commercial ‘pipelines within a pipeline’.
5.26 Physical connection already exists between Moomba and Adelaide for gas flows absent the MAPS. That is, gas can flow via the MSP and interconnector and Victorian Principal Transmission System, then via SEA Gas to Adelaide. When consideration is given to the use of swaps, presumably holders of contracts for Moomba gas who wish delivery in Adelaide could actually swap with Sydney users currently sourcing via Gippsland (or Otway) using the EGP or interconnect so that the Sydney users source gas from Moomba via the MSP while the Adelaide users source gas from Gippsland or Otway via SEA Gas. The increasing use of swaps as a mechanism to increase market flexibility has been highlighted by the announcement by Santos of a gas swap between the Cooper Basin producers and Origin Energy Retail (see Box 1).16
5.27 Epic Energy concludes that it is clear that it is already possible to physically transport gas to Adelaide while not using the MAPS and that both upstream and downstream markets have multiple alternative service options. As such, the physical evidence indicates it is economic to duplicate the MAPS and therefore criterion (b) is not satisfied for the Moomba to Adelaide main line.
16 Santos News Release, 6 May 2004
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Box 1 Cooper Basin producers gas swap with Origin Energy Retail
The South West Queensland Gas Producers signed a Heads of Agreement with Origin Energy Retail for the swapping of gas between Queensland and the Moomba Gas Hub. The agreement is designed to provide Origin with access to up to 200 PJ of gas at the Moomba Gas Hub in central Australia, and includes a mechanism to increase this amount.
It is expected that the first gas to be swapped under the agreement will occur during 2004 with the amount of gas dependent on South Australian and New South Wales requirements. Under the agreement, gas swapping would continue until the end of 2011.
Nature of the gas swap
Origin has agreed to deliver gas produced in its central Queensland fields to the Producers at Roma in Queensland. The Producers will then use this gas to meet part of their customer requirements in south-east Queensland.
In return for the gas from Origin, the Producers will redirect (swap) an equal quantity of Cooper Basin produced gas to Origin at the Moomba Gas Hub.
These swapped gas volumes are expected to be used by Origin to supply its customer base in South Eastern Australia in conjunction with other supplies of gas, including Cooper Basin gas already purchased by Origin.
Having access to swapped gas at the Moomba Gas Hub eliminates the need for Origin to construct major additional pipeline infrastructure in the short term.
Benefits to the Producers in swapping gas
Under the Heads of Agreement, the Producers will receive swap fees from Origin for the quantities of gas to be delivered to Origin at the Moomba Gas Hub. The Producers will also receive increased gas liquids revenue as a result of processing incremental gas at the Moomba Gas Hub, which recovers higher levels of gas liquids than the Producers’ processing facilities at Ballera in south-west Queensland.
MAPS lateral pipelines 5.28 The MAPS not only delivers gas to Adelaide via the main pipeline but also provides gas transportation services to Whyalla and Port Pirie, and to the Angaston area. Issues with these lateral pipelines so far as criterion (b) is concerned are discussed below.
Port Pirie/Whyalla lateral 5.29 The Port Pirie/Whyalla lateral is approximately 183 km in length with a replacement cost value in the order of $36 million. The off-take is located at KP590, or approximately 150 kilometres north of the point of closest proximity to the SEA Gas pipeline (near the Penfield Roses meter station). Average throughput on the Port Pirie/Whyalla lateral is somewhat less than 18 TJ/day, or some 6.5 PJ per annum, with a maximum firm capacity of 24 TJ/day. The lateral is currently fully contracted (24 TJ/day) and no spare capacity exists.
5.30 Of this amount, the majority (approximately 15 TJ/day) is sold for use by a single customer under a contract due to expire in 2005. Epic Energy is currently in the process of commercial negotiations with customers on the Whyalla lateral. Epic Energy is seeking to establish a long term, ten year, contract for the majority of the capacity on this lateral. To the extent it is successful in this regard, the only remaining available capacity (and existing demand) will be for gas transport to Port Pirie and other, minor Whyalla loads. This demand is unlikely to be sufficient
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to justify coverage in and of itself especially given Epic Energy’s commitment that the surcharge for a Port Pirie transport service will not exceed the lesser of the price established under any long term contract or the current surcharge rolled forwards as discussed in paragraph 6.45. That is, any new user on the Port Pirie/Whyalla lateral will effectively have a reference tariff to guide their negotiations with Epic Energy.
5.31 In addition, the physical characteristics of the lateral mean that there is a very real economic possibility of bypassing the mainline to Port Pirie section of the lateral. This is associated with the historical development of the lateral whereby an initial 6 inch pipeline was installed to Port Pirie with subsequent extension by way of an 8 inch pipeline from Port Pirie to Whyalla. Thus, the mainline to Port Pirie section of the lateral is the principal constraint on meeting increased demand. This also means that there is potential for a third party to economically bypass the mainline to Port Pirie section if they could contract for the Port Pirie load.
5.32 Clearly, sufficient capacity exists on the MAPS to allow backhaul from Adelaide to the Port Pirie off take either directly with Epic Energy or by way of a swap arrangement with an existing shipper. This possibility will effectively constrain Epic Energy’s ability to price above the stand alone cost of a new pipeline (from the mainline to Port Pirie.
5.33 Currently, the regulated tariff for the lateral surcharge (which is effectively an average price to Whyalla) is set as $0.18/GJ in 2001 with a 95% CPI annual adjustment.
Angaston lateral 5.34 The Angaston lateral is some 41 km in length with an estimated replacement cost of $8 million. The Angaston lateral off-take is located at KP 731 (or near the Wasleys compressor station). Average throughput on the Angaston lateral is less than 10 TJ/day or around 3.5 PJ/year.
5.35 The Angaston lateral connects with the Envestra owned Riverland pipeline system (an uncovered transmission pipeline) at the downstream point of the lateral. There is currently no connection between SEA Gas and the Riverland pipeline system. SEA Gas does however cross the Riverland pipeline quite close to Murray Bridge so there is the possibility to connect the pipeline at that point. This would allow gas to flow into Murray Bridge from SEA Gas and reverse the flow of the Riverland pipeline to flow gas into Mildura and Berri. The physical proximity of these pipelines is highlighted in the map provided in paragraph 6.23.
5.36 The physical connection of the two pipelines is not considered a major task, although it is acknowledged that a number of commercial and technical issues would apply related to pressure regulation and changes to valves.
5.37 The bypass potential on the Angaston Lateral due to the low capital cost of either interconnection with the SEA Gas pipeline or duplication of the existing lateral is further supported by the reasonable gas demand of around 3.5PJ/yr, which would suggest that contracts for only a proportion of the load would be sufficient to support bypass.
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5.38 However, to the extent it is considered that the possibility of bypass is insufficient to prevent monopoly pricing then Epic Energy notes its commitment to continuing the current tariff structure whereby no separate charge is levied for use of the Angaston lateral, with the tariff being solely that applicable for transport on the mainline. As such, Angaston lateral users will continue to benefit from the price competition resulting from the entry of the SEA Gas pipeline into the South Australian market.
Conclusions on uneconomic to duplicate
Moomba to Adelaide main line 5.39 Clearly, if a point to point definition of service is applied to the Covered Pipeline, over the next 10 to 15 years, demand for gas transport services can be met by the existing asset (with appropriate enhancements).
5.40 However, it is equally clear that it is already possible to physically transport gas to Adelaide from Moomba and elsewhere while not using the Covered Pipeline and that both upstream and downstream markets have multiple alternative service options. As such, the physical evidence indicates it is economic to duplicate the Covered Pipeline and therefore criterion (b) is not satisfied for the main line section of the Covered Pipeline.
Port Pirie/Whyalla lateral 5.41 In terms of the Port Pirie/Whyalla lateral, it is clear that the existing pipeline can satisfy likely demand for services over the medium term and as such, is uneconomic to duplicate in a social cost sense.
5.42 However, the fact that a long term (ten year) contract is currently being negotiated for gas to Whyalla effectively covering the majority of the available capacity on the lateral, will leave only limited additional capacity (principally into Port Pirie) as uncontracted. The cost of building a pipeline to service only this demand is likely to be relatively low and given the available capacity on the mainline it is considered that commercial bypass of this section is a real possibility in circumstances where Epic Energy attempts to exercise market power. As such, it is considered that duplication of this lateral is likely to be commercially feasible.
Angaston laterals 5.43 In terms of the Angaston lateral, it is clear that the existing pipeline can satisfy likely demand for services over the medium term.
5.44 However, the lateral is likely to be easily bypassed given that the Riverland Pipeline (which the Angaston Lateral connects with) crosses the SEA Gas pipeline providing a relatively cheap option to source competing gas. Further, the off take for the Angaston Lateral is close to Adelaide city and therefore the end of the SEA Gas pipeline. This fact, coupled with the low capital cost of the lateral,
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creates a real risk of competitive bypass of the lateral. As such, it is considered that it is economic to duplicate the Angaston lateral.
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6. Grounds for revocation - Criterion (a)
6.1 Criterion (a) is satisfied where it can be shown:
that access (or increased access) to services provided by means of the pipeline would promote competition in at least one market (whether or not in Australia), other than the market for the services provided by means of the pipeline
Approach to assessing criterion (a) 6.2 The approach adopted by the NCC in addressing Criterion (a) was outlined most recently in the GGP Final Recommendation, namely:
(a) define the relevant market(s) in which competition may be promoted and verify that this market or these markets are separate from the market for the service to which access is sought; and (b determine whether access (or increased access) facilitated by coverage would promote a more competitive environment in the additional market(s), which requires an assessment of:
(a) whether the provider has the ability and incentive to exercise market power to adversely affect competition in the dependent market(s); and
(b) whether the structure of the dependent market(s) is such that coverage would, by constraining the exercise of market power by the service provider to adversely affect competition in the dependent market(s), promote competition.
6.3 Epic Energy considers that this framework is an appropriate one for addressing criterion (a) and as such it is followed here.
6.4 In addressing the definition of the relevant markets, Epic Energy considers that what is important is to recognise that it is the constraints that the structure and composition of the market impose on the exploitation of market power that are important and not the market definition itself. The process of defining a market is helpful in identifying and organising relevant information, but it is not necessarily definitive with respect to the competition issue under consideration. What is important is to consider all factors that could effectively constrain the exploitation of market power.
6.5 This is consistent with legal precedent, for example, the Full Federal Court in QWI stated:17
17 Queensland Wire (1987) FCR 211 at 218-9.
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In defining the market or markets involved in a particular dispute, I should begin with problem at hand and ask what identification of market best assists in analysing the processes of competition, or lack of competition, with which the case is concerned.
6.6 Accordingly, when defining the relevant markets under consideration, the key concern is to do so in a way that enables the assessment of the market power that may or may not be possessed by the service provider.
6.7 This is consistent with the views expressed by the NCC in its GGT Final Recommendation, where the NCC noted that assessment of criterion (a):18
does not require a precise definition of the boundaries of the market for the access service. What must be determined is whether there are distinct markets; that is, the market(s) in which competition is said to be promoted (i.e. the dependent market(s)) must be shown to be different from the market for the access service. Accordingly, the Council does not consider it is necessary to precisely define the boundaries of the market in which GGT supplies the Service.
6.8 The issue therefore is to ensure that the dependent markets involved in the production and sale of gas are functionally separate from the market for gas transmission services which Epic Energy contends occurs within the south-east Australian interconnected gas transmission network.
6.9 It is Epic Energy’s view that the relevant markets for the purposes of assessing criterion (a) are:
• The upstream market for gas production and sales at the Moomba and Ballera hubs;
In terms of downstream markets, it is considered that there are three fundamental markets:
• a downstream gas sales market along the MAPS and the Port Pirie/Whyalla lateral;
• a downstream gas sales market in south-east Australia; and
• a downstream electricity sales market in the Victorian and South Australian region of the NEM.
6.10 The basis for determining these relevant markets is discussed below, however, it is noted that these markets are consistent with the definitions developed by the
18 GGT Final Recommendation 5.39
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NCC in the GGP Final Recommendation and are consistent with precedent established in other revocation applications.
6.11 The process of defining a market involves four key market dimensions, namely – function, product, geography and time:
• function refers to the stage of the activity in the production or distribution chain for a good or service;
• product refers to the types of products available to meet demand, noting that this can change as technology and relative prices change;
• geography refers to the spatial definition of the market and concerns the distribution of firms across space who can meet market demand; and
• time refers to the time period over which substitution possibilities are considered and actual and potential competitors identified.
6.12 This framework is applied to upstream and downstream markets in arriving at the relevant markets for assessment of criterion (a).
Market Definition - Upstream market(s) 6.13 Clearly, the starting point for definition of the product dimension of the upstream market dependent upon the MAPS is the market for the production and sale of the product transported by the MAPS, that is, natural gas. As it is considered that there is no additional product that is a close substitute and would therefore serve to expand the product dimension of the market, Epic Energy concludes that the product dimension is limited to natural gas.
6.14 As highlighted in Table 12, the Cooper Eromanga basin is still a major source of natural gas supply for south eastern Australia, with annual production estimated to be around 230 PJ in 2004/05 and commercial reserves in 2002 estimated to be around 3,500 PJ.
6.15 In terms of the geographic boundary of the market for the production and sale of natural gas, the starting point is clearly the producers currently served by the MAPS, namely, those producers utilising the Moomba hub. Given the raw gas pipeline interconnection between the Ballera and Moomba gas processing plants, and the fact that south west Queensland producers already send gas to Moomba for processing and sale, the geographic extent must include Ballera. It is not considered feasible economically or technically for producers further afield (such as coal seam methane producers in the Bowen or Surat Basin’s) to connect to the MAPS, therefore, Epic Energy considers that the appropriate geographic dimension is limited to producers connecting to the Moomba and Ballera hubs.
6.16 Epic Energy considers that there are unlikely to be any changes in the foreseeable future that would impact on substitution possibilities relevant to the definition of the upstream market and therefore finds that the relevant upstream
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market is the market for gas production and sale at the Moomba and Ballera hubs.
Market Definition - Downstream market(s) 6.17 Epic Energy considers that the relevant downstream markets are:
• a downstream gas sales market along the MAPS form Moomba to north of the Angaston lateral;
• a downstream gas sales market in south-east Australia; and
• a downstream electricity sales market in the Victorian and South Australian region of the NEM.
6.18 The selection of these markets has been driven by the availability (or lack thereof) of close technical and economic substitutes for gas provided by the MAPS.
6.19 The MAPS main line is a 22 inch pipeline extending some 780 km from Moomba to Adelaide. However, it is possible to separate the mainline into that section north of the Angaston lateral and that section from the lateral south. The lower section effectively interconnects with the Adelaide distribution system and the SEA Gas pipeline and can be argued to be part of the south-east Australian gas market as discussed below.
Downstream gas sales market along the MAPS from Moomba to north of the Angaston lateral 6.20 There are a number of delivery points north of the Angaston lateral. These are detailed in the following table together with the approximate distance along the mainline from Moomba and approximate gas demand in 2003.
Offtake KP TJ/yr Beverly Uranium Mine 244 Peterborough Township 559 Hallet 604 Burra 640 Mintaro 665 Sub Total Main Line Offtakes 840 Port Pirie/Whyalla Lateral 590 8,000 Total 8,840
6.21 The above connection points may be divided into two principal categories, firstly, customers taking gas for their own use and secondly, intermediaries taking gas
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for resale to third parties over local distribution networks. Examples of the later category would include Peterborough, Port Pirie and Whyalla township. Customers taking gas for their own use include the Beverly Uranium Mine.
6.22 Epic Energy is of the view that for the majority of customers located along the mainline from Moomba to north of the Angaston lateral, while there may be technical substitutes available for the gas supplied from the MAPS (such as liquid fuels), such substitutes are not economic – that is they fail the test of combined technical and economic substitution and as such, users along this section are solely reliant on the MAPS. This is particularly likely given the low tariffs on the MAPS and the current high cost of liquid fuels. For example, even if it were possible to get liquid fuel such as kerosene delivered for $0.40/litre, and assuming an energy value of around 34 MJ/litre, the energy cost would be around $12/GJ compared with a likely energy cost from natural gas of significantly less than $4/GJ (paragraph 4.11).
6.23 However, this argument does not apply to users on the Angaston lateral as can be seen on the following map. This indicates that the Envestra owned Riverland system includes a southern extension to Murray Bridge which extends to close proximity with the SEA Gas pipeline. This existing pipeline provides the very real potential for interconnection with the SEA Gas pipeline and therefore provides Angaston lateral users with a technically and economically viable substitute to gas sourced from the MAPS.
6.24 On the above basis, it is concluded that the product dimension is limited to natural gas, while the functional dimension includes users purchasing gas for their own use and users purchasing gas for re-sale. The geographic dimension is
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determined by direct users’ proximity to the MAPS while the geographic dimension associated with users reselling gas is determined by the extent of their distribution networks. Finally, Epic Energy is not aware of any foreseeable factors likely to impact on these conclusions.
6.25 Therefore, Epic Energy concludes that there is a distinct downstream gas sales market along the MAPS from Moomba to north of the Angaston lateral.
Downstream gas sales market in south-east Australia 6.26 There are three Adelaide distribution connection points off the MAPS. These are, Gepps Crossing, Elizabeth and Taperoo. In 2003 gas delivered through these points was approximately 28,500 TJ.
6.27 The physical location of these points in relation to the MAPS and SEA Gas pipeline is highlighted in the following map. Gas delivered to these connection points is resold to a variety of residential and commercial consumers. Internal constraints within Envestra’s Adelaide distribution network mean that gas delivered at a single connection point (for example, Gepps Crossing), cannot physically be delivered to every point within the network.
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6.28 Currently, the SEA Gas pipeline only delivers gas to the southern section of the distribution network via the Cavan meter station. However, the SEA Gas pipeline passes in close proximity to Gawler which is the northern extent of the distribution network as well as passing the Elizabeth meter station and various other distribution nodes and there does not appear to be any technical or economic reason why SEA Gas would not be able to deliver gas to the northern end of the distribution network should sufficient demand be apparent. Therefore, the internal constraints outlined in paragraph 6.27 are not binding as they can be readily and economically addressed by further SEA Gas interconnection
6.29 As can be seen from the above map, the SEA Gas and MAPS parallel each other for a considerable distance and even physically cross. Thus, while there is currently no direct physical connection between these two pipelines, such a connection is considered to be both technically and economically possible. At present there is some difference in the gas specification between the two pipelines and interconnection would require agreement to ensure neither party
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was technically or commercially disadvantaged. Initial discussions have been held between the pipelines with the aim of identifying and addressing interconnection issues and no insurmountable issues have been identified. However, at this stage no pressing commercial justification for interconnection has been identified and therefore the interconnection has not been undertaken.
6.30 Given that gas delivered to the distribution network is for resale, the product dimension of the market is considered to be limited to natural gas and the functional dimension is users purchasing gas for re-sale.
6.31 In establishing the geographic dimension, it is important to assess the impact of the recent interconnection of South Australia within the south-east Australian interconnected natural gas network. The commissioning of the SEA Gas pipeline has created the situation where gas sourced from Moomba and delivered for resale in Adelaide can readily be resold into Victoria or even Sydney. Such resale may take the form of physical delivery of the gas via backhaul on the SEA Gas pipeline or through parties entering into swap agreements between different market nodes. As such, the geographic dimension is extended to include the south-east Australian interconnected gas transmission network encompassing SA, Victoria, NSW and potentially, Queensland.
6.32 In terms of the temporal dimension of the market, it is clear that there is ongoing change in Australia’s gas transmission network as additional pipelines are commissioned and new sources of gas developed. The impact of this is that, over time, there is clear evidence of increasing competition as multiple pipelines connect demand nodes providing both competition for transport services and competition between different sources of gas. The impact of these changes is likely to be the progressive broadening of the market.
6.33 On the basis of the above discussion, Epic Energy considers that there is a distinct dependent market for gas sales in south-east Australia.
Downstream electricity sales market in the National Electricity Market area 6.34 As discussed in Attachment B, South Australian demand for electricity has been met from a combination of sources including imports from other regions within the NEM and local coal and gas fired generation as indicated in Table 4.
Table 4 Proportion of SA electricity consumption by generation source Consumption Year TWh Coal Import Gas 2000 12.8 35.4% 23.6% 41.0% 2001 12.9 33.7% 12.8% 53.5% 2002 12.9 32.4% 11.4% 56.1% 2003 12.8 32.3% 22.5% 45.2%
6.35 The above table and the discussion in Attachment B identified that over 50% of the total natural gas consumption in South Australia is related to the use of gas to generate electricity.
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6.36 Further, the discussion in Attachment B identified that South Australia is a fully integrated component of the NEM, with NEMMCO commenting that Victoria and South Australia are treated as a single region due to the fact that: 19
• supply-demand balance is dependent on the network capability into Victoria from Snowy and Tasmania (post Basslink commissioning);
• Victoria to South Australia interconnectors do not constrain the flows in or out of South Australia during high demand periods; and
• regions are subject to similar weather patterns.
6.37 As such, Epic Energy considers that there is a distinct downstream product market in respect of electricity sales.
6.38 Epic Energy does not consider that there is any benefit in terms of the assessment of criterion (a) in functionally separating the wholesale and retail electricity markets. This is consistent with the view expressed by the NCC with respect to the GGT.20
6.39 Epic Energy considers that the geographic dimension is bounded by the Victorian and South Australian region within the NEM.
6.40 In considering the time dimension, Epic Energy notes that there is ongoing investment in extending the interconnection within the NEM. For example, Bass Link is expected to be commissioned in late 2005 and NEMMCO’s annual SOO identifies emerging constraints that require resolution. As such, over time it is expected that the market will continue to expand.
6.41 On the basis of the above discussion, Epic Energy concludes that there is a separate downstream electricity sales market in the NEM.
Market Definition Conclusions 6.42 Epic Energy concludes that the relevant markets for assessment of criterion (a) are:
• the upstream market for gas production and sales at the Moomba and Ballera hubs;
In terms of downstream markets, it is considered that there are three fundamental markets:
• a downstream gas sales market along the MAPS and the Port Pirie/Whyalla lateral;
19 NEMMCO 2004 Statement of Opportunities Executive Summary p.3 20 NCC GGT Final Recommendation. 5.171
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• a downstream gas sales market in south-east Australia; and
• a downstream electricity sales market in the Victorian and South Australian region of the National Electricity Market.
Promotion of competition – Approach to assessing 6.43 Epic Energy believes that sufficient precedent exists with respect to the assessment of criterion (a) to ensure that it is uncontentious to argue that the test for the promotion of competition involves a “with and without” assessment. That is, would the conditions for competition be enhanced by coverage under the Code compared to the conditions absent coverage. Indeed, this view has been expressed by the NCC most recently in its GGP Final Recommendation.21
6.44 As the MAPS is a covered pipeline, the conditions for competition without coverage will of necessity be somewhat less clear than is the case for a coverage application such as that argued with respect to the EGP (that is, for a pipeline that has not been subject to access regulation). Nevertheless, Epic Energy has already outlined the dramatic increase in competitive market conditions and the associated expected impact on its market share of the commissioning of the SEA Gas pipeline and will further develop that argument below.
6.45 In addition, it is also important to reiterate that Epic Energy is committed to ensuring that all customers, irrespective of their location along the pipeline, will be able to take advantage of the benefits accruing from the increased competitive conditions resulting from the commissioning of the SEA Gas pipeline. In particular, Epic Energy reiterates its commitment that:
• all customers north of Adelaide (who are not directly exposed to the benefits of competition from the SEA Gas pipeline), are assured of paying no more than the price offered at the time a new or renewed service is sought for a similar service to Adelaide (this does not preclude Epic Energy offering a lower price should it decide to move from the current flat (postage stamp) tariff to some other tariff structure such as distance or zonal based);
• users of the Port Pirie and Whyalla lateral, who currently pay a surcharge in addition to the mainline tariff, are assured that the surcharge will not exceed the price offered under long term contract or the rolled forward escalated surcharge identified in the current Access Arrangement, whichever is the lesser; and
• Epic Energy is committed to transparent open access on all its gas transmission pipelines and will continue to develop and implement a behavioural Code of Conduct, consistent with, and based on, that
21 NCC GGT Final Recommendation para. 5.206 on.
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promulgated by the Australian Pipeline Industry Association as discussed in paragraph 4.15.
6.46 In considering previous revocation applications, the NCC has raised the issue of the possibility of collusion between alternative service providers or vertical leveraging by the service provider.22 In this context, the multiple interconnections and spare capacity inherent in the current interconnected south-east Australian pipeline network suggest that price collusion would be very difficult to successfully implement. Further, the ability to enter into long term contracts for gas transport together with the limited number of users in the market (see paragraph 6.76) increases the difficulty of successful collusion due to the incentives faced by any given market participant to undercut its partners and sign up the limited available customers. In addition, in implementing its version of the industry Code of Conduct outlined in para 4.15, Epic Energy is committed to protecting confidential information through effective, audited, ring-fencing of staff.
6.47 Thus, the principal area of concern must remain the possibility that Epic Energy will have sufficient market power to be able to sustainably raise prices above the competitive level, thereby extracting monopoly profits.
6.48 The first step in assessing this issue is to establish what the competitive price level would be. Epic Energy agrees with the NCC that the current price need not necessarily represent the price likely to prevail in a competitive market.23 Rather, the concept of an efficient price needs to be assessed in the context of the requirement of the firm to cover the efficient long run economic costs as recognised by the NCC.24
6.49 To assist the NCC in understanding the efficient long run economic costs, Epic Energy has undertaken a Hypothetical New Entrant Test (HNET) based on the estimated cost that would be faced by a new entrant to provide the service provided by the MAPS, that is, contracts for firm transport of approximately 70 PJ of gas from 2006. This approach is consistent with the ACCC’s Draft Statement of Principles for the Regulation of Transmission Revenues (May 1999) in terms of calculating a competitive revenue requirement. It is also likely to be broadly consistent with a reference tariff established under the Code, given that the initial capital base of the MAPS has been established and the remaining key variable in establishing a price cap reference tariff will be establishing a demand forecast – such a forecast would clearly be consistent with that mooted by Epic Energy post 2006. In this context, it is important to note that a revised Access Arrangement is due to be lodged by 1 July 2005 with the new arrangements scheduled to commence from 1 January 2006.
6.50 The use of forecast volumes for the MAPS rather than total SA volumes is also considered appropriate in that any hypothetical new entrant would assess the likely maximum volumes they would be likely to capture bearing in mind potential customers very real desires to maintain diversified supply sources both for
22 NCC GGT Final Recommendation para 5.222 23 NCC GGT Final Recommendation para 5.27 24 NCC GGT Final Recommendation para 5.200(b)
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security of supply purposes and to capture the benefits of basin on basin competition. That is, pipeline users will not simply move to the lowest cost pipeline, rather, they will seek to minimise the total delivered cost of gas together with risks associated with their portfolio of supply options.
6.51 The long run efficient price for a new entrant based on this approach was estimated to be $0.85/GJ using a smoothed 20 year price escalating at 95% of CPI (or $0.92/GJ based on a single year building block cost). This compares with the current MAPS tariff of approximately $0.49/GJ. Details of this analysis are provided in Attachment C. This analysis provides a clear indication of the lack of market power likely to be possessed by the MAPS, as Epic Energy does not believe that a price of $0.85 would be sustainable in the current market with the most recent indication of pricing on the SEA Gas pipeline suggesting capacity could be available at around $0.63/GJ. However, it is questionable whether even this would be a market bearable price for he MAPS.
6.52 The next step is to consider the time frame over which the possible ability and incentive to use market power should be assessed. Epic Energy believes that a time frame similar to the used by the ACT in the EGP case is appropriate, namely, 10 to 15 years.25
6.53 We now turn to consideration of the possible ability of MAPS to wield market power in each of the markets we have determined.
Promotion of competition - the upstream market 6.54 The upstream market has been defined as the market for gas production and sales at the Moomba and Ballera hubs. In order to assess whether coverage under the Code would promote competition compared to the world without coverage requires that consideration be given to whether upstream producers have substitute markets they can access in circumstances where Epic Energy was to introduce a small but significant and non-transitory increase in price (“SSNIP”) above long run economic costs.
6.55 As discussed in Attachment B, the Moomba (and Ballera) producers currently have access (or potential access) to markets in Mt Isa, South East Queensland, NSW, Victoria, Tasmania and South Australia. Indeed, the commissioning of the EGP has meant that the Moomba to Sydney pipeline has considerable excess capacity. That is, the total NSW natural gas market was estimated to be in the order of 140 PJ in 2004 while combined developable pipeline capacity is estimated to be in excess of 400 PJ of which the MSP represents some 290 PJ. Further, Moomba gas is currently competing in the south-east Australian market with gas sourced from other basins such as Gippsland and Otway. That is, the close proximity of all of these supply sources to major demand centres and multiple transport options means that gas from any of these basins is likely to find its way into each of the demand centres at differing times.
6.56 In addition, there is clear evidence of increasing use of gas swaps supporting virtual interconnection of the Queensland gas market with the south-east
25 Duke Eastern Gas Pipeline Pty Ltd [2001] ACompT 2 para 99
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Australian gas market. Discussion of recent evidence of such swaps was presented in Box 1.
6.57 As noted in this discussion, the impact of the swap agreement is to negate the need for immediate development of additional infrastructure such as a sales gas pipeline between Moomba and Ballera. That is, the use of gas swaps will ensure that the physical path need not necessarily be used and that the cheapest delivered gas will flow to each centre.
6.58 In addition to the fact that upstream users have a number of viable substitutes for the service provided by the MAPS, there is also evidence that even absent such substitution possibilities, that coverage would not enhance the conditions for competition due to the structure of the upstream market. That is, the existing barriers to entry in this market due to the joint marketing arrangements together with the maturity of the gas fields and relative lack of prospectivity suggest limited potential for improvement in competitive conditions associated with coverage of the MAPS.
6.59 On the basis of the above discussion, Epic Energy considers that it neither has the ability or incentive to use market power in the upstream market for gas production and sales at the Moomba and Ballera hubs.
Promotion of competition - the downstream gas sales market along the MAPS and the Port Pirie/Whyalla lateral 6.60 Gas consumption along the MAPS north of the Angaston lateral is currently around 9 PJ/yr of which approximately 8 PJ/yr is delivered via the Port Pirie/Whyalla lateral. As discussed in paragraph 5.30, Epic Energy is currently negotiating a long term contract (10 years) for the majority of the capacity on this lateral. The remaining capacity is currently used to service the remaining minor customers, principally at Port Pirie.
6.61 As there is no spare capacity on the Port Pirie/Whyalla lateral, any expansion would only be likely to be undertaken in conjunction with supporting long term contracts. Therefore, there is only in the order of 2 to 3 PJ/yr of gas consumption in the downstream market north of the Angaston lateral that could be potentially impacted by Epic Energy’s use of any market power it may have, absent coverage.
6.62 As discussed under criterion (b), Epic Energy acknowledges that users along the MAPS (north of the Angaston lateral) and on the Port Pirie/Whyalla lateral do not generally have access to substitutes for natural gas delivered by the MAPS that would be both technically and economically feasible. Therefore, superficially it may appear that Epic Energy could have the ability and incentive to use market power.
6.63 However, as discussed above, Epic Energy is committed to ensuring that customers along the mainline and the Port Pirie/Whyalla lateral are able to share in the benefits arising from the competitive market for gas sales in south-east Australia. Therefore, Epic Energy will ensure that:
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• all customers along the mainline currently paying the main line reference tariff will pay no more than the price offered at the time a service is sought for a similar service to Adelaide;
• users of the Port Pirie and Whyalla lateral who currently pay a surcharge in addition to the mainline tariff, are assured that the surcharge will not exceed the price offered under long term contract or the rolled forward escalated surcharge whichever is the lesser; and
• development and implementation of a behavioural Code of Conduct is continued.
6.64 Epic Energy is aware that some parties may feel that, notwithstanding Epic’s commitment to the introduction of the Code of Conduct, there is greater certainty of no misuse of market power under the Code. However, Epic does not believe that this is grounds for continued coverage especially given the fact that even where coverage of the MAPS is revoked, it remains open for any party to seek coverage should they feel that Epic Energy is misusing market power. Indeed the threat of regulation is generally accepted to be an effective form of control. That is, one of the strengths of self regulation is that there remains the threat of more invasive steps being taken should the industry led arrangements be seen to fail. The ACT in the EGP case made explicit reference to this very point in the context of determining that coverage of the EGP was not required:26
Thirdly, there is a threat of regulation as an application for coverage can be made at any time….
In these circumstances the prices that EGP can charge for transport will be constrained if market development is to be successful. And there is the threat of regulation, with its associated costs, if prices are increased.
6.65 Similar sentiments have been expressed by the Productivity Commission: 27
The effectiveness of monitoring regulation depends in part on the threat of access arrangement with reference tariffs regulation possibly being applied in the future. The service provider’s commercial behaviour will be influenced by the threat of being subject to access arrangement with reference tariffs regulation at the end of five years.
6.66 The efficacy of the threat of regulation was also recognised by the Commonwealth Taskforce on Industry Self Regulation:28
26 Paragraph 130, 132. 27 Productivity Commission (2004). Review of the Gas Access Regime, p385. 28 Taskforce on Industry Self-regulation: Industry Self-Regulation in Consumer Markets (2000), p25.
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The actual or perceived ‘threat’ of government regulation, or a ‘push’ by government because of poor industry practices was found to be a further reason for industry to self- regulate. For example, the Code of Banking Practice was primarily developed by a committee of officials and implemented by Australian banks.
6.67 Epic Energy considers that given:
• the small amounts of gas involved;
• Epic Energy’s commitment to protect users to the north of the Angaston lateral;
• the introduction of the Code of Conduct; and
• the very real threat of coverage being reimposed should it seek to misuse market power
Epic Energy neither has the ability or incentive to misuse market power in the market for gas sales north of the Angaston lateral and along the Port Pirie/Whyalla lateral.
Promotion of Competition - Downstream gas sales market in south- east Australia 6.68 Epic Energy does not believe that coverage will enhance the conditions for competition in the downstream gas sales market in south-east Australia due to the commercial drivers faced by the MAPS associated with operating a high capital low operating cost asset, the existence of significant spare pipeline capacity, the competition it faces from the SEA Gas pipeline and the countervailing power of other market participants. These arguments are developed below.
6.69 The competitive situation in the downstream gas sales market in south-east Australia over the next ten to fifteen years will at least in part be a function of the level and location of gas reserves and the extent of pipeline capacity available to deliver gas between different demand and supply nodes. Detailed analysis of supply and demand issues is provided in Attachment B and key findings from that section are reproduced below.
6.70 Eastern Australian sources of supply are summarised in the following table.29 This table indicates that at the rate of extraction occurring in 2000/01, existing commercial reserves are likely to be exhausted around 2020 although it is expected that significant components of the non-commercial reserves will become commercial over that period and that additional discoveries will also be made.
29 Dickson and Noble 2003. Eastern Australia’s Gas Supply and Demand Balance. APPEA Journal 2003 p137
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Eastern Australian gas reserves (PJ) 2002 Non- Production Basin Commercial commercial Total 2000/01 Adavale 14 – 14 1 Bass – 376 376 – Bowen–Surat 107 122 229 24 Cooper–Eromanga 3,503 913 4,416 211 Gippsland 5,974 2,055 8,029 239 Otway 30 1,670 1,700 8 Total 9,628 5,136 14,764 483
6.71 In the medium term, as identified by ABARE and discussed in Attachment B, it is anticipated that additional sources of gas supply will be developed and become available at the Moomba hub. This is likely to include ongoing development of coal seam methane together with the increasing likelihood that the PNG gas pipeline project (or a competing northern source of gas) will be developed. In addition, the Otway Basin area appears reasonably prospective and it is likely that additional gas discoveries will be made augmenting supplies into Adelaide via the SEA Gas pipeline. As such, these existing sources of supply, together with the introduction of new sources, are expected to supply south-east Australian centres for the ten to fifteen year period of interest for this analysis.
6.72 In terms of gas transmission pipeline infrastructure capacity, as highlighted in Figure 3 of attachment B, current pipeline capacity into each of the main demand centres in south-east Australia significantly exceeds current demand and, together with developable capacity will continue to significantly exceed forecast demand for at least the next fifteen years (Figure 4 of attachment B). However, some limited transmission system augmentation is likely to be required in Victoria given the limitations of the Port Campbell to Portland link (currently approximately 190 km of 6 inch pipe) should there be sufficient demand in Melbourne for Otway Basin gas.
6.73 The impact of this level of interconnection is that, for example, gas users in Adelaide can readily choose to meet part, or all, of their demand from producers supplying at the Moomba hub, from the Otway basin producers or via swaps, from Gippsland basin producers.
6.74 An additional factor limiting the incentives of pipeline companies to seek to price above competitive levels is the high capital and low operating costs associated with gas transmission infrastructure which provides strong incentives to maximise throughput as noted by the ACT:30
There are strong commercial incentives for Duke to increase the throughput of the EGP, given its high capital cost, low operating costs and spare capacity
30 Duke Eastern Gas Pipeline Pty Ltd [2001] ACompT 2 para 117
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6.75 Given the significant current and developable capacity existing in both the SEA Gas pipeline and the MAPS, both companies will have strong incentives to compete vigorously to secure market share.
6.76 Further, the limited counterparties involved in gas transportation are well informed and understand the underlying economics of the pipeline sector and, as such, have significant countervailing negotiating power as outlined in APIA’s submission to the Productivity Commission review of the National Gas Access Regime where APIA noted:31
…pipeline companies tend to have a limited number of very large customers. …on average across all major pipelines, the top three customers represent 88% of the throughput with this percentage increasing to 94% when the top 5 customers are considered.
…pipeline customers tend to be significant and experienced users of pipeline services. Given that information on the economics of pipelines is readily available from engineering consultancy firms, pipeline customers are well informed and well placed to negotiate for the provision of services. Conclusion 6.77 Epic Energy contends that the Covered Pipeline does not currently, and will not over the next ten to fifteen years have, sufficient market power to hinder competition in the south-east Australian market for gas sales. This is due to the commercial drivers associated with operating a high capital, low operating cost asset, the existence of significant spare pipeline capacity in the MAPS, the competition it faces from the SEA Gas pipeline and the countervailing power of other market participants.
Promotion of Competition - Downstream electricity sales market 6.78 Epic Energy believes that coverage will not enhance the conditions for competition in the downstream electricity sales market in the Victorian and South Australian region of the NEM as the market already exhibits effective competition and the NEM’s gross pool spot market structure removes the ability of any participant in the energy chain (such as the MAPS) to sustainably raise prices.
6.79 In Attachment B, Epic Energy outlined the current status of gas fired generation in the NEM together with a discussion of the impact of structural issues. The results of that discussion may be summarised as:
• the majority of South Australia’s 3,200 MW of installed generating capacity is gas fired (78%) although gas fired plant typically only satisfied between 45% and 55% of South Australia’s total demand for electricity over the period 2000 to 2003, with the remainder being met from coal fired generation (32%) and imports from interstate (12% to 22%);
31 APIA September 2003, Submission to the Productivity Commission’s Review of the National Gas Access Regime. p18
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• import capacity into South Australia from Victoria is some 680 MW with export capacity of around 420 MW. NEMMCO have stated that the Victoria to South Australia interconnectors do not constrain the flows in or out of South Australia during high demand periods; and
• average power prices in South Australia are equivalent to average Victorian prices after adjusting for inter-regional loss factors.
6.80 The implication of the above factors is that electricity imports from Victoria serve to constrain the price achieved by South Australian generators. The impact of the interconnection between Victoria and South Australia is highlighted by the fact that the commissioning of the Murraylink interconnector and increased utilisation of the Heywood interconnector resulted in electricity imports to South Australia increasing by some 1.4 TWh or some 11% of total South Australian electricity demand in 2003. This increase in imported electricity was matched by a decrease in South Australian gas fired generation as a proportion of total consumption from 56% to 45%.
6.81 The inevitable consequence of any attempt by the Covered Pipeline to significantly increase the transport tariff paid by gas fired generators would be either a reduction in demand for transport services or a move on the part of the generator to seek gas supply over the SEA Gas pipeline.
6.82 As such, the Covered Pipeline does not have the ability to charge higher prices and coverage under the Code will not improve the conditions for competition compared to those that would apply absent coverage.
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7. Grounds for revocation - Criterion (c)
7.1 Criterion (c) is satisfied where it can be shown:
"that access (or increased access) to the services provided by means of the pipeline can be provided without undue risk to human health or safety"
7.2 Epic Energy does not consider that coverage under the Code will cause undue risk to human health or safety and therefore believes that criterion (c) is satisfied.
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8. Grounds for revocation - Criterion (d)
8.1 Criterion (d) is satisfied where it can be shown
“that access (or increased access) to the services provided by means of the pipeline would not be contrary to the public interest"
8.2 A key concern in establishing whether or not coverage would be against the public interest must be an assessment of the relative costs and benefits associated with coverage. While it is very difficult to accurately assess such costs and benefits, it must be recognised that application of the Code imposes real and significant costs on businesses.
8.3 Such costs include both the direct costs incurred by both the service provider and the regulator (and other involved parties) as well as the indirect costs of regulation as acknowledged by the Productivity Commission in its review of the Code:32
Based on the Commission’s assessment (of both costs and benefits), including taking into account input from interested parties, it is reasonable to conclude that there are problems with the current regime. These mainly arise from the considerable costs the regime imposes and its real potential to distort investment and inhibit innovation.
8.4 Therefore, it is incumbent upon the NCC to acknowledge that the Government has accepted the Productivity Commission’s recommendations on the need for change to the Code although the resulting changes have not as yet been enacted.
8.5 Epic Energy’s experience is that the direct costs of regulation of the MAPS have been very high and have required a protracted process culminating in an appeal of elements of the ACCC’s Access Arrangement for the MAPS. Leaving aside the costs of management time, costs of external consultants alone totalled in excess of $800,000.
8.6 Further, the next regulatory review will not necessarily be any easier given likely issues related to the impact of competition from SEA Gas and the implied need for significant increases in reference tariffs under a building block price cap framework.
8.7 Moreover, the MCE has indicated that a user pays system is to be implemented whereby the industry is to pay for the costs of the establishment and operation of the two new national regulators that have been established – the Australian Energy Regulator and the Australian Energy Market Commission. While the draft framework for the funding of these bodies is yet to be outlined, based on the
32 Productivity Commission Inquiry Report Review of the National Gas Access Regime pXXVII
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experiences of transmission pipeline owners in Western Australia, these costs for the Covered Pipeline could exceed $1 million per annum.
8.8 The costs of regulation are not simply measured in terms of direct costs, rather, of potentially greater concern are the dynamic efficiency impacts of regulation. This is an issue identified by the Productivity Commission who noted in the Review of the National Access Regime that costs of regulation included: 33
• administrative costs for government and compliance costs for business;
• constraints on the scope for access providers to deliver and price their services efficiently;
• reduced incentives to invest in facilities to provide new essential services or to maintain existing facilities;
• inefficient investment in downstream markets; and
• wasteful strategic behaviour by both service providers and access seekers.
The Productivity Commission went on to note that:
Third party access and the resulting benefits to service users are only possible over the longer term if there is continuing investment in the essential infrastructure services themselves. On the other hand, while denial or monopoly pricing of access imposes costs on the community, such behaviour cannot threaten the continued availability of the services concerned. This asymmetry in potential outcomes highlights the priority that access regulation must give to ensuring that there are appropriate incentives for efficient investment.
8.9 The impact of these incentive effects is becoming increasingly clear, for example, with the current problems faced by users of the Dalrymple Bay Coal Terminal in getting the lease holder to agree to expand capacity in the face of a draft regulatory ruling suggesting significantly reduced access prices.
8.10 As such, at a minimum, it is argued that an appropriate response for the NCC is to err on the side of caution in considering the costs and benefits of regulation under the Code and therefore to only recommend coverage where there are clear and material benefits from so doing.
8.11 An example where coverage would not be justified would be where the NCC accepts that the Covered Pipeline has no market power in either the upstream market for gas production and sales, or the downstream markets for gas sales in south-east Australia or in the downstream electricity sales market, but finds that the Covered Pipeline may have market power in the downstream market for gas sales north of the Angaston lateral. Then, the small size of this market and Epic
33 Productivity Commission 2001, Review of the National Access Regime, Report no. 17, AusInfo, Canberra. pg XVIII
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Energy’s commitment to the development and introduction of a behavioural code of conduct together with the prospect of coverage in the future should the Covered Pipeline attempt to misuse market power, mean that the NCC should not recommend continued coverage of the Covered Pipeline.
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10. Glossary
ABARE Australian Bureau of Agricultural and Resource Economics
ACCC Australian Competition and Consumer Commission
Act Gas Pipelines Access (South Australia) Act, 1997 (or "GPAA")
ACT Australian Competition Tribunal
AGA Australian Gas Association
APIA Australian Pipeline Industry Association
APPEA Australian Petroleum Production and Exploration Association
ASKs Available Seat Kilometres
ASX Australian Stock Exchange
BTRE Bureau of Transport and Regional Economics
CCGT Combined Cycle Gas Turbine
CoAG Council of Australian Governments
Code Third Party Access Code for Natural Gas Pipeline Systems
Commission Productivity Commission
CS Compressor Station
CPI Consumer Price Index
DBNGP Dampier to Bunbury Natural Gas Pipeline
Duke Duke Energy International Pty Ltd
EECSS Epic Energy Corporate Shared Services Pty Ltd
EGP Eastern Gas Pipeline
EGP Decision "Duke Eastern Gas Pipeline Pty Ltd [2001] ACompT2", Australian Competition Tribunal, 4 May 2001
GDP Gross Domestic Product
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GGP Goldfields Gas Pipeline
GGT Goldfields Gas Transmission Pty Ltd
GJ GigaJoule (ie. 109 Joules)
GWh Gigawatt hour
HNET Hypothetical New Entrant Test
IPO Initial Public Offering
Km Kilometre
LPG Liquid Petroleum Gas
LRMC Long Run Marginal Cost
MCE Ministerial Council on Energy
MW MegaWatt
MAPS Moomba to Adelaide Pipeline System
MSP Moomba to Sydney Pipeline
NCC National Competition Council
NEM National Electricity Market
NEMMCO National Electricity Market Company
NSW New South Wales
NT Northern Territory
OCGT Open Cycle Gas Turbine
PASA Pipeline Authority of South Australia
PJ PetaJoule (ie. 1015 Joules)
PJ/yr PetaJoule (ie. 1015 Joules) per year
Qld Queensland
RPKs Revenue Passenger Kilometres
SRMC Short Run Marginal Cost
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SSNIP Small but Significant and Non-transitory Increase in Price
SOO Statement of Opportunities
Tas Tasmania
Tcf 1012 cubic feet
TGP Tasmanian Gas Pipeline
TJ/d TerraJoule (ie. 1012 Joules) of gas per day
TPA Trade Practices Act 1974
TWh TerraWatt hour
Tribunal Australian Competition Tribunal
Vic Victoria
WA Western Australia
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ATTACHMENT A
Confidential Maps
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To be inserted
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ATTACHMENT B
Energy Market Analysis
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Energy Market Analysis B1 This attachment provides detailed discussion of key gas and electricity market issues. The aim of this discussion is to identify the key factors likely to impact on gas supply and demand within south and eastern Australia over the next ten to fifteen years. In addressing this question, Epic Energy has based its analysis on the most recent publicly available data sources. Key factors discussed include:
• identification of demand growth forecasts and discussion of variances between different data sources;
• impact of depletion of existing gas reserves and identification of potential new reserves;
• impact of existing pipeline network on ability to meet demand for transport from new reserves;
• the role of gas fired electricity generation in South Australia; and
• discussion of NEM structure and impact on competition in South Australia.
Gas Supply B2 While Australia has very significant proven and probable gas reserves in comparison to its consumption level, the majority of such reserves are located in the north and north west of Australia – areas remote from the main south-east Australian gas demand centres. Indeed the Carnarvon, Browse and Bonaparte Basins together account for over 90% of current natural gas reserves as highlighted in Figure 1 and Table 5.
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Figure 1 Australian natural gas reserves and gas transmission pipeline infrastructure
Data source: Dickson and Noble 2003. Eastern Australia’s Gas Supply and Demand Balance. APPEA Journal 2003 p 136
Table 5 Australian gas reserves (PJ) 2002 Non- Production Commercial commercial Total 2000/01 Eastern Australia 9,628 5,136 14,764 483 Northern and central Australia 345 60,761 61,106 19 Western Australia 23,641 59,023 82,664 731 Total 33,614 124,920 158,534 1,233 Eastern Australian as % of total 28.6% 4.1% 9.3% 39.2%
Note: Non-commercial reserves are those that are recoverable but not yet profitable to produce Source: Dickson and Noble 2003. Eastern Australia’s Gas Supply and Demand Balance. APPEA Journal 2003 p 137
B3 However, local eastern Australian reserves of gas have been more than sufficient to underpin the initial development of a significant gas market at least in part driven by the close proximity of commercial reserves to major demand centres. Current estimated reserve levels within the eastern Australian area are detailed in Table 6.
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Table 6 Eastern Australian gas reserves (PJ) 2002 Non- Production Basin Commercial commercial Total 2000/01 Adavale 14 – 14 1 Bass – 376 376 – Bowen–Surat 107 122 229 24 Cooper–Eromanga 3,503 913 4,416 211 Gippsland 5,974 2,055 8,029 239 Otway 30 1,670 1,700 8 Total 9,628 5,136 14,764 483
Source: Dickson and Noble 2003. Eastern Australia’s Gas Supply and Demand Balance. APPEA Journal 2003 p 137
B4 The above information provides a static picture of the current level of reserves. It is to be expected that continued exploration activity together with changes in exploration and extraction technology and market characteristics, will lead to both an increase in total reserves and a change in the mix of those reserves (with a greater proportion of existing reserves becoming commercial over time). While the majority of growth in reserves is expected in the Carnarvon, Browse and Bonaparte basins, it is likely that expansion of reserves in eastern Australian basins will also occur. For example, Geoscience Australia noted that:34
The Casino gas discovery has confirmed the presence of an active petroleum system in this part of the offshore Otway Basin and has enhanced the prospectivity of a number of additional prospects which have a seismic response similar to that present over the Casino gas field…
B5 As such, the above reserve estimates represent the lower limit of expected reserves.
Gas Demand B6 Demand information with respect to natural gas consumption in Australia exhibits significant variability depending on the source of the data. While total gas field production figures are expected to be relatively reliable, there is decreasing accuracy as the data is disaggregated. For example, estimates of consumption for the main eastern Australian States is provided in Table 7 for the 2000/01 year. This table contains demand information sourced from ABARE35 and contrasts it with information from the Productivity Commission Review of the Gas Access Regime36.
34 Geoscience Australia. Oil and Gas Resources of Australia 2002. p.26 35 Dickson and Noble 2003. Eastern Australia’s Gas Supply and Demand Balance. APPEA Journal 2003 p 143 36 Productivity Commission 2004 Review of the Gas Access Regime p.16
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Table 7 Eastern Australian Natural Gas Consumption 2000/01 (PJ) Demand ABARE 2003 PC (AGA) PC % Inc over ABARE NSW 141 142 0.7% Victoria 236 251 6.4% Queensland 78 79 1.3% SA 112 135 20.5% Tasmania 0 0 0.0% Total 567 607 7.1%
B7 The greatest variation in Table 7 is seen in the South Australian forecasts with the Productivity Commission’s estimate of 135 PJ being some 20% higher than ABARE’s estimate of 112 PJ. In terms of the quantity of natural gas delivered to South Australia, it is a licensing requirement that annual throughput of the MAPS is reported to the South Australian Minister for Energy. In both 2001 and 2002, this was approximately 100 PJ with throughput decreasing to 91.5 PJ in 2003.
B8 The decreased consumption in 2003 reflects the commissioning of the Murraylink interconnector and increased utilisation of the Heywood interconnector with electricity imports to South Australia increasing by some 1.4 TWh or some 11% of total South Australian electricity demand in 2003. This increase in imported electricity was matched by a decrease in South Australian gas fired generation as a proportion of total consumption from 56% to 45%.37
B9 The MAPS throughput prior to commissioning of the SEA Gas pipeline is considered to be a reasonable proxy for South Australian natural gas demand. However, it will understate demand to some degree due to gas transported via the South East Pipeline (approximately 4 PJ/yr) and fuel gas used on the MAPS (around 1 PJ/yr). Adjusting for these factors suggests total natural gas demand or around 105 PJ in 2001 and 2002 and 96 PJ in 2003. These figures are considered the most appropriate baseline for demand forecast purposes.
B10 It is clear that the increasing acceptance of gas as a fuel of choice in Australia has resulted in the demand for gas increasing. This increase is in the order of 6.9% per annum over the last 25 years with total Australian consumption of natural gas currently estimated to be around 1,000 PJ per annum. This represents approximately 19% of Australia’s total primary energy consumption, a proportion that is forecast to increase to 24% or more than 1,800 PJ by 2019- 20.38
B11 ABARE also provides regular independent medium term growth forecasts for natural gas. In their most recent August 2004 energy projections, ABARE have forecast a rapid, although gradually slowing, increase in demand for natural gas with a long term average increase from 2001/02 to 2019/20 of around 3.4% per annum (Table 8)39.
37 www.nemmco.com.au 38 ABARE August 2004. Australian Energy national and state projections to 2019-20. p23 39 ABARE June 2003. Australian Energy national and state projections to 2019-20.
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Table 8 ABARE 2004 Eastern Australian Natural Gas Consumption 2001/02 to 2019/20 (PJ) Av Annual Eastern Inc from NSW Vic Qld SA Tas Aust Total 01/02 2001-02 130.9 243.8 85.6 141.8 0.0 602.1 0.0% 2004-05 140.0 263.6 126.6 139.2 9.9 679.3 6.2% 2009-10 163.7 308.2 164.8 166.3 17.8 820.8 4.5% 2014-15 189.0 357.7 185.2 185.2 20.0 937.1 3.8% 2019-20 215.7 408.6 212.4 206.7 21.4 1,064.8 3.4%
B12 It should be noted that this revised forecast differed significantly from ABARE’s 2003 forecast (Table 9). ABARE comment that the 2004 projections are an update of the June 2003 projections but do not explain the variances between the forecasts. Clearly the 2004 projections are the most recent although it may be that the modelling approach used has resulted in some variation from actual consumption. For example, the revised (2004) prediction for South Australia in 2004/05 of 139 PJ is a significant increase over the 2003 forecast for the same year of 117 PJ.
Table 9 Comparison of ABARE 2003 and 2004 gas consumption estimates (PJ) ABARE 2003 ABARE 2004 ABARE 2003 ABARE 2004 Est for Est for Est for Est for 2004/05 2004/05 Difference 2019/20 2019/20 Difference NSW 173 140 -33 230 216 -14 Vic 273 264 -9 388 409 21 Qld 115 127 12 177 212 35 WA 406 369 -37 749 632 -117 SA 117 139 22 193 207 14 Tas 7 10 3 20 21 1 NT 31 35 4 131 132 1 Aust Total 1,122 1,084 -38 1,888 1,828 -60
B13 For the purposes of this analysis the 2004 projections have been used as these are the most recent available. In the medium term (out around 2019), the differences are not so significant and are unlikely to materially impact on our conclusions with respect to market power.
B14 It should be noted that Table 8 is based on primary energy consumption and as such includes LPG and ethane, butane and propane transported from Moomba via the Port Bonython liquids line. This significantly impacts on total South Australian natural gas consumption and as such, base 2001/02 natural gas consumption for South Australia (delivered by pipeline) has been set at 105 PJ. Demand over the period to 2019-20 has been increased at the same rate as used by ABARE. This results in an adjusted natural gas forecast for South Australia as detailed in Table 10.
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Table 10 Revised South Australian Natural Gas Consumption 2001/02 to 2019/20 (PJ) Percentage Original Revised Increase 2001-02 141.8 105.0 2004-05 139.2 103.1 -1.8% 2009-10 166.3 123.1 19.5% 2014-15 185.2 137.1 11.4% 2019-20 206.7 153.1 11.6%
B15 The demand data discussed above has been presented as published in the original source documents. However, in discussing pipeline capacity and constraints, it is generally more appropriate to use daily demand figures which are normally expressed in terms of TJ/day. In the following sections, this convention is used.
Transmission infrastructure B16 Gas transmission infrastructure is the critical link allowing the delivery of gas from production sites to often relatively remote demand centres. A key issue for any market analysis will be the location and capacity of such transmission infrastructure with respect to sources of supply and demand. The location of major Australian pipelines is presented in
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Figure 2.
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Figure 2 Australian Gas Transmission Pipelines
2004
Gove DARWIN Mt T odd Daly Waters McArthur River Townsville Varanus Island Port Hedland Mt Isa On slow Dampier Telfer Alice Newman Springs Barcaldine Fairview
BRISBANE Moomba Ballera Wallumbilla
Kalgoorlie Kambalda PERTH Berri Griffith Newcastle SYDNEY Esperance Wag ga ADELAIDE CANBERRA Murray Wodonga Bridge MELBOURNE Sale Existing Pipelines L ong fo rd Hamilton Pipelines Built During this Port Latta Bell Bay Period Proposed / Under HOBART Development
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B17 The indicative capacity of transmission pipeline infrastructure in eastern Australia is highlighted in Table 11. This capacity is on the basis of estimates of the nominal fully compressed capacity at a 100% load factor. Clearly, the currently configured capacity may be substantially lower than quoted in this table. Similarly, the actual load factor will be significantly below 100% and will vary depending on the nature of the use of gas amongst other factors. In an attempt to highlight the impact of load factor, indicative actual daily capacity based on a 75% load factor is also provided.
Table 11 Estimated pipeline capacity (fully compressed) Fully Compressed Capacity at Capacity 75% load Pipeline (TJ/day) factor Moomba to Sydney 795 596 Moomba to Adelaide 418 313 SEA Gas 411 308 EGP 301 226 SWQP 301 226 Roma to Brisbane 137 103 QGP 142 107 Carpentaria 137 103 Interconnect 52 39 TGP 178 134
B18 The notional capacity outlined above is not in fact the maximum theoretical capacity of these pipelines as it is generally technically feasible to continue to install additional compression to increase throughput although at increasing marginal cost. Capacity can also be increased via looping. As such, the above capacity is an indication of the pipeline developers original thinking with respect to economically viable maximum pipeline capacity.
Supply and demand balance
B19 A key issue in establishing whether a specific pipeline is likely to have significant market power is the inter-relationship between the demand for gas and the available sources of supply and therefore the likely demand for services with respect to particular pipelines. The above discussion outlined forecasts of sources of supply and changes in demand by State. ABARE have sought to address the question of supply sufficiency by applying its MARKAL model of the Australian energy system.
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B20 In undertaking this modeling, ABARE developed a base set of assumptions, including:40
• production from the Cooper-Eromanga field was fixed to decline from 235 petajoules in 2001–02 to 190 petajoules by 2019–20, ostensibly to reflect reduced reservoir deliverability and increasing extraction costs;
• production from the Gippsland Basin was bounded to a maximum of 360 petajoules a year in the period to 2019-20;
• production from the Otway and Bass Basins were similarly bounded to maxima of 125 and 20 petajoules a year, respectively;
• total Australian coal seam methane supplies were fixed, increasing from 34 petajoules a year in 2000–01 to 100 petajoules a year in 2019–20; and
• A northern pipeline option was required to deliver a minimum of 100 petajoules to the Moomba hub.
B21 This modelling indicated the progressive change in the source of gas as demand continues to increase in eastern Australia, with a source of northern gas (possibly sourced from PNG or Timor Sea), required to be delivered to Moomba by around 2012/13. The results of this modelling are reproduced in Table 12. A graphical representation of the interaction between sources of supply, demand centres and current pipeline infrastructure is provided in Figure 3 and Figure 4 for the years 2004/05 and 2019/20 respectively.
Table 12 Eastern Australian Gas Supply Sources 2004/05 to 2019/20 (PJ) Basin 2004–05 2009–102010–11 2011–12 2012–13 2013–14 2014–15 2019-20 Bass 20 2020 20 20 20 20 20 Bowen-Surat 13 1010 10 0 0 0 0 Cooper–Eromanga 228 215 213 210 208 205 203 190 Gippsland 265 318336 358 337 345 348 360 Otway 63 125125 125 77 90 77 125 Subtotal 588 688704 723 642 660 648 695 CSM 60 8182 83 85 86 90 100 Ethane 36 3636 36 36 36 36 36 Total Eastern Supply 685 805 822 842 763 782 774 831 Northern supply option 0 0 0 0 100 100 129 177 Total Production 685 805 822 842 863 882 903 1,008
40 Dickson and Noble 2003. Eastern Australia’s Gas Supply and Demand Balance. APPEA Journal 2003 p 142
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Figure 3 Indicative Eastern Australian Supply and Demand – 2004/05
D: Mt Isa 28 PJ
TxC: CGP 50 PJ TxC: QGP 52 PJ
D: South East Qld 75PJ
TxC: MAPS 28 PJ S: Copper Eromanga 228 PJ S: Bowen Surat/CSM TxC: RBP 50 PJ 13 PJ
D: NSW 173 PJ
TxC: MAPS 160 PJ + SEA TxC: MSP 290 Gas 150 PJ = 310 PJ PJ + EGP 110 PJ + Interconnect 20 = 420 PJ PJ
D: SA 117 PJ
S: Gippsland S: Otway 63 PJ 265 PJ
D: Vic 273 PJ TxC: Western TxC: Longford to Interconnector 10 PJ Melbourne 400 PJ
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Figure 4 Indicative Eastern Australian Supply and Demand – 2019/20
D: Mt Isa 40 PJ
TxC: CGP 50 PJ TxC: QGP 52 PJ
D: South East Qld 140PJ
TxC: MAPS 28 PJ S: Copper Eromanga 190 PJ + Northern Gas 180 PJ = Total 370 PJ S: Bowen Surat/ Qld TxC: RBP 50 PJ CSM 60 PJ
D: NSW 230 PJ
TxC: MAPS 160 PJ + SEA TxC: MSP 290 Gas 150 PJ = 310 PJ PJ + EGP 110 PJ + Interconnect 20 = 420 PJ PJ
D: SA 190 PJ
S: Gippsland S: Otway 125 360 PJ PJ D: Vic 390 PJ TxC: Western TxC: Longford to Interconnector 10 PJ Melbourne 400 PJ
B22 Figure 4 highlights the fact that the SA market is likely to continue to be faced with excess pipeline capacity at least until 2020 even allowing for the possible impact of northern gas delivered via Moomba.
Electricity market impacts on gas demand B23 The above discussion identified broad, high level, estimates of changes in gas demand and supply in Australia. Of particular concern in South Australia is the impact of changes in electricity demand and therefore likely changes in gas fired electricity generation. Over recent years, SA demand for electricity has been met from a combination of sources including imports from other regions within the National Electricity Market (“NEM”) and local coal and gas fired generation (Table 13).
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Table 13 Proportion of SA electricity consumption by generation source Consumption Year TWh Coal Import Gas 2000 12.8 35.4% 23.6% 41.0% 2001 12.9 33.7% 12.8% 53.5% 2002 12.9 32.4% 11.4% 56.1% 2003 12.8 32.3% 22.5% 45.2%
B24 Table 13 highlights both the lack of growth in total electricity consumption over the four calendar years form 2000 to 2003 and the relatively stable proportion of the SA electricity market serviced by local coal fired generation which acts as the preferred base load supply. The greatest volatility is between imports and local gas fired generation where an increase in imports in 2003 saw a commensurate decrease in local gas fired generation and, therefore, demand for gas as discussed further below.
B25 The above level of local gas fired generation (in Adelaide) is estimated to account for over 50% of total natural gas demand in South Australia (based on a 45% average energy efficiency rate for gas fired generation and the 2003 total demand for gas of 91.5 PJ). A lower energy conversion efficiency would significantly increase this proportion.
B26 The key part played by electricity demand and the proportion satisfied by local gas fired generation in determining the demand for gas in South Australia means that more detailed discussion of electricity demand and the future role of gas fired generation is essential.
B27 The following discussion focuses on current gas fired generation together with forecast investment in gas generation over the next ten to fifteen years. In addition, network constraints likely to affect NEM regions are briefly outlined as is the current status of hydro generation which is likely to be the most significant competitor for gas fuelled mid to peak load generation.
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(a) National Electricity Market
B28 The National Electricity Market (NEM) commenced operation in December 1998, and is comprised of Queensland, NSW, ACT, Victoria and South Australia with Tasmania to join in 2005 six months prior to the commissioning of the Basslink interconnector.
B29 The NEM includes nearly 8 million customers and in 2002/03 sent out nearly 168,000 GWh of energy. It is operated on a gross pool spot market design basis, where all wholesale transactions are settled within the market at the prevailing market clearing spot price. The spot price is established as the average for a 30- minute trading interval (comprised of six 5-minute dispatch intervals).
B30 Approximately 38,000 MW of generation capacity is installed within the NEM. Actual availability at any point in time will vary with factors such as scheduled maintenance, outages and current plant operating efficiency (which may be impacted by prevailing temperatures etc). A guide to the generation capacity installed by geographic region and fuel type is provided in Table 14.
Table 14 NEM summer 2002/03 generation capacity by region and fuel type (MW) Fuel NSW Vic Snowy QLD SA Total Black Coal 11,451 7,995 19,446 Brown 6,438 640 7,078 Coal Gas 160 1,346 457 2,520 4,483 Oil 44 786 38 868 Hydro 320 578 3,676 632 5,206 TOTAL 11,975 8,362 3,676 9,870 3,198 37,081
Source: ACIL Tasman April 2003, SRMC and LRMC of Generators in the NEM p.3.
B31 This table highlights the preponderance of coal fired generation within the NEM which accounts for over 70% of the installed capacity with gas and hydro accounting for the majority of the remainder.
B32 The equivalent information for energy generation by fuel type and region is provided in Table 15. This table highlights the base load nature of coal fired generation which, while representing approximately 70% of installed capacity, generated around 90% of total energy. However, South Australia exhibits a significantly different pattern with the majority of energy generated from gas fired plant.41
41 The difference between the ACIL Tasman data and the NEMMCO data outlined in Table 13 is likely to be related to underlying data sources and treatment of electricity imports. That is, the ACIL Tasman numbers are based on local generation only.
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Table 15 NEM 2002 generated energy by region and fuel type (GWh) Fuel NSW Vic Snowy QLD SA Total Black Coal 62,624 46,819 109,443 Brown 48,959 4,208 53,167 Coal Gas & Oil 979 1,256 589 7,254 10,078 Hydro 256 989 3,543 397 5,185 TOTAL 63,859 51,204 3,543 47,805 11,462 177,873
Source: ACIL Tasman April 2003, SRMC and LRMC of Generators in the NEM p.4.
B33 Three of the key factors that have influenced the current nature of NEM operations are:
• the historical development of electricity infrastructure as State government owned and operated assets;
• the location of major fuel sources and relative price of fuels; and
• demand volatility Historical development of infrastructure B34 Early development of electricity infrastructure involved a mix of private and public investment, however, as the scale of operations increased and the move to a centralised, coordinated network began, State Governments’ increasingly took responsibility for planning and developing the electricity network. Invariably this involved the delivery of electricity to consumers via state owned, vertically integrated monopolies. Another characteristic of this State control and focus on State independence and self-sufficiency was that only limited interconnection was developed between the states and it is only in recent years that any attempt has been made to address inter-regional constraints so as to minimise significant regional price differences.
Fuel availability, location and relative cost
B35 The main fuel types used in different regions of the NEM are a reflection of the combined impact of relative fuel costs and availability. Thus, of total energy generated in NSW, Victoria and Queensland, over 95% (after adjusting for the Snowy) is generated using coal. In contrast, South Australia (which lacks access to the very large and accessible coal reserves of the other states), generates over 60% of total energy using gas and oil (Table 16).
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Table 16 NEM 2002 generated energy by region and fuel type (%) Fuel NSW Vic Snowy QLD SA Total Black Coal 98% 0% 0% 98% 0% 62% Brown Coal 0% 96% 0% 0% 37% 30% Gas & Oil 2% 2% 0% 1% 63% 6% Hydro 0% 2% 100% 1% 0% 3% TOTAL 100% 100% 100% 100% 100% 100%
Source: ACIL Tasman April 2003, SRMC and LRMC of Generators in the NEM p.4.
B36 This preference for coal fired generation is a direct function of the relatively low cost of such generation. ACIL Tasman has estimated the Long Run Marginal Cost (“LRMC”) for coal and gas generation in various locations within the NEM. Their results are reproduced in Table 17. This analysis suggested that Queensland black coal generators had the lowest LRMC ($31.42/MWh) for sent out energy while the cheapest gas fired electricity was estimated to be from Queensland combined cycle gas turbines at $41.93/MWh. That is, electricity generated from the cheapest gas fired plant was estimated to be at least 33% more expensive than electricity generated from the cheapest coal fired plant.
Table 17 LRMC of energy sent out by fuel type and location Generation type $/MWh Queensland Black Coal 31.42 NSW Black Coal 34.66 Victoria Brown Coal 33.60 Queensland CCGT 41.93 Victoria CCGT 43.77 NSW CCGT 44.14 SA CCGT 45.33 OCGT 5% Cap 183.47 OCGT 10% Cap 126.77
Source: Source: ACIL Tasman April 2003, SRMC and LRMC of Generators in the NEM p.48 B37 A complicating factor for pricing within the NEM is that prices are set at the regional reference point within each State. This price may reflect inter regional transmission constraints with the result that regional reference prices can diverge significantly across the NEM. This issue is discussed further below. In addition, the actual price received by an individual generator will be a function of their location relative to the regional reference point and the impact of transmission loss factors associated with transporting energy to the reference point from the point of generation.
B38 Coal fired generation (and hydro generation) are invariably located adjacent to fuel sources which may be a significant distance from major demand centres leading to increased price adjustments relative to the regional reference point. By contrast, gas fired generation plant can be located adjacent to centres of demand assuming gas transmission infrastructure exists.
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Demand volatility B39 The demand for electricity within the NEM exhibits both strong seasonal variability and diurnal variability. This is highlighted in Figure 5, which shows the average demand experienced by region in the NEM together with the all time maximum demand. In general, average demand is around two thirds of maximum demand although in South Australia, the ratio is closer to one half.
Figure 5 Average Demand All Time Peak Demand (MW) at June 2003
14,000 12,456 12,000
10,000 8,358 8,572 7,912 8,000
MW 5,608 6,000 5,480
4,000 2,832
2,000 1,477
0 QLD NSW VIC SA Region
Average Demand A ll Time Max imum Demand
Data source: NEMMCO
B40 Generally, maximum demand variability is associated with temperature variations (either cold or heat). Increasingly, maximum demand is associated with high temperatures due to the increasing penetration of home air-conditioning. Intra day peak demand is generally driven by domestic activity with two peaks occurring around 0700 to 0900 and 1600 to 1900. This demand volatility is matched by a similar (volatile) price profile as highlighted in Figure 6, where the 30 minute trading interval price for NSW on 28/08/03 can be seen to vary between approximately $13/MWh to around $25/MWh while demand varies between a low of 6,800 MW to a peak of 8,800 MW.
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Figure 6 Typical Demand/Price Profile NSW 28/08/03
12,000 $26
11,000 $24
10,000 $22 ) 9,000 $20
8,000 $18
7,000 $16 Price ($/MW) Demand (MW Demand
6,000 $14
5,000 $12
4,000 $10
0 0 0 0 0 0 :0 :0 :0 2 4:00 0 8 00:0 0 0 06:00 08:0 1 12:00 14:00 16:0 1 20:00 22:00 Time
Demand Pr ic e
Data source: NEMMCO
B41 This price volatility is attributable to a combination of generator bidding strategies, plant availability and underlying generation characteristics. As noted above, different fuel sources have differing underlying cost structures. Similarly, different generation technologies have varying abilities to rapidly respond to changing NEM conditions.
B42 For example, steam driven generators (such as all coal fired plant), take anything from 8 to 48 hours to reach operational readiness from a cold start. In contrast, gas turbines will typically be able to commence generating within 20 or so minutes of commencing startup. Finally, hydro generators typically are able to commence generating within a minute or so of commencing startup. This means that it is only gas turbines and hydro powered generators that are able to respond to short term variations in demand and price without risking significant losses associated with being ready to generate in circumstances where plant is not dispatched. That is, in order to use steam generators as a standby power source, they must continuously burn fuel, adversely impacting on profits in circumstances where they are not dispatched into the market.
Increase in gas fired generation B43 As noted above (Table 14), there is approximately 4,500 MW of gas fired generation capacity within the NEM which (on ACIL Tasman’s figures), generated some 10 TWh of electricity in 2002. [Note: the exact level of
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generation attributable to gas fired generators is not clear with ABARE quoting 15 TWh for the NEM states in 2001/02.42]
B44 ABARE has forecast that Australia’s demand for electricity will increase by more than 50% by 2019-20. This is estimated to require some 8,400 MW of additional gas and coal fired generation capacity. Of this, ABARE forecast some 4,660 MW will be gas fired with 3,600 MW of this being located in the NEM states. This is an increase of around 80% in gas fired generation capacity. While installed gas fuelled generation capacity is forecast to increase by 80%, the energy generated is forecast to increase by almost 160% indicating increased capacity utilisation of new gas generation plant. The forecast growth in energy generated by gas fuelled plant is presented in Table 18.
Table 18 Gas fuelled electricity generation by NEM state (TWh) 2001-02 2008-092019-20 Growth % Increase
NSW 2.1 3.1 5.7 3.6 171%
Victoria 2.1 3.6 6.8 4.7 224%
Queensland 3.1 9.4 12.4 9.3 300%
SA 7.5 9.2 12.4 4.9 65%
Tasmania 0 0.6 0.9 0.9 NA
Total 14.8 25.9 38.2 23.4 158%
Source: Akmal, M. et al, Australian Energy: National and State Projections to 2019-20, ABARE eReport 04.11, Canberra..
B45 This table highlights that the major increase in gas fired generation is expected to occur in the eastern states, and in particular, in Queensland (at least in part due to that State’s adoption of the 13% gas scheme). The increase in South Australia is relatively modest at only 65% although still significant representing as it does some 4.9 TWh of electricity. This is the equivalent of some 35 PJ of gas assuming 3.6 PJ to the TWh of electricity and a 50% efficiency rate for new (CCGT) gas generation plant. The additional pipeline capacity required to service this potential demand is significantly below the spare capacity already found in the South Australian market.
Network constraints (interconnection between regions) B46 A potentially significant constraint limiting the NEM’s ability to ensure consistent prices across the entire market is the ability of transmission infrastructure to deliver electricity from centralised generation plant to often distant centres of demand. The greatest level of competition in the NEM would be achieved in circumstances where there were no instances where regional reference prices diverged thereby allowing any market generator wherever it is located to respond to emerging demand possibly in another NEM region.
B47 The current capacity to transfer power between NEM regions is highlighted in Table 19.
42 Akmal, M. et al, Australian Energy: National and State Projections to 2019-20, ABARE eReport 04.11, Canberra
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Table 19 Interconnection capacity within the NEM (MW) Export Import NSW to QLD (QNI) 700 950 NSW to QLD (Directlink) 180 180 Snowy to NSW Winter 3,200 Summer 2,800 1,150 Victoria to Snowy 1,100 1,900 Vic to SA (Heywood) 460 300 Vic to SA (Murraylink) 220 120
Source: Energy In Australia 2004 ABARE p35. B48 The utilisation of this available interconnection capacity is highlighted in Figure 7. This figure shows the significant net inflows into South Australia of some 2,915 GWh during 2003, giving an average utilisation of interconnection capacity of around 329 MW of a notionally available 680 MW.
Figure 7 Snapshoot of NEM 2003
Data source: Energy In Australia 2004 ABARE p36.
B49 In NEMMCO’s 2004 Statement of Opportunities, NEMMCO noted that the combined Victorian/South Australian region would continue to suffer a (generation) reserve deficit even after Basslink was commissioned. This deficit
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was forecast to be some 306 MW in 2006/07. NEMMCO treated Victoria and South Australia as a single region due to the fact that43:
• supply-demand balance is dependent on the network capability into Victoria from Snowy and Tasmania (post Basslink commissioning);
• Victoria to South Australia interconnectors do not constrain the flows in or out of South Australia during high demand periods; and
• regions are subject to similar weather patterns.
B50 As there is no binding network constraint between South Australia and Victoria, the price separation that occurred in 2003 between the South Australian average price of $29/MWh and the Victorian average price of $25/MWh, is purely a function of inter regional transmission loss factors together with any scheduling and dispatch decisions resulting in higher priced generation in South Australia being dispatched under a NEMMCO nominated market constrained condition.
Peaking plant capacity availability B51 As noted above, the characteristics of steam generators make them unsuited for the role of peaking plant. This role is currently filled by a combination of gas turbine and hydro generating plant. An indication of the nominal capacity of peaking capable plant (reflecting interconnector capacity) is provided in Table 20.
Table 20 Peaking capacity in the NEM (MW) NSW Vic Qld SA Interconnector max 3,830 2,400 880 680 Other Hydro 320 578 632 Gas Turbine (any fuel) 212 979 1,954 1,439 Total 4,362 3,957 3,466 2,119 As % of Peak Demand 35% 46% 44% 76%
B52 The above estimated peaking capacity assumes independent regions with the maximum in any region dependent upon local available plant and interconnector capacity. The exception is South Australia, where it is assumed that peak requirements will coincide with Victoria and the Victoria to South Australia interconnectors will operate fully to export to South Australia.
Given the assumptions underpinning the peaking capacity estimates, they should be taken as indicative only. Nevertheless, they are suggestive of substantial installed generation capacity capable of responding to short term price signals in the market.
43 NEMMCO 2004 Statement of Opportunities Executive Summary p.3
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ATTACHMENT C
Application of the Hypothetical New Entrant Test
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Introduction C1 In addressing criterion (a) in recent major revocation cases, the NCC has relied on the approach developed by Ordover and Lehr in their November 2001 paper, “Should Coverage of the Moomba-Sydney Pipeline be Revoked?”.
C2 Ordover and Lehr argued that one of the best indicators of whether a pipeline is able to exploit its natural monopoly in the provision of pipeline services to a pertinent group of customers, is whether current prices are substantially above long-run economic costs (which it is argued is the level they should attain in the presence of effective competition).
C3 Ordover and Lehr acknowledged the difficulties of estimating competitive prices in network industries and the fact that while prices might fall below long-run average costs in the short-run, in the long-run firms must be able to recover their costs. While not explicitly stating it, this implicitly recognises that at any point in time prices may vary either above or below long-run average costs.
The MSP precedent C4 In their paper, Ordover and Lehr used the ACCC’s draft reference tariff as a proxy for the competitive price. Given that this price was around $0.43/GJ and the MSP headline tariff was around $0.708/GJ, they concluded this was evidence that competition was insufficient to discipline prices in line with what could be expected in a competitive market. This argument was subsequently vigorously attacked by EAPL and their consultants (NECG). EAPL suggested, to the extent that the comparison of current pipeline tariffs with hypothetical tariffs had any relevance, it was limited to comparing the price of a Hypothetical New Entrant (HNE) with the incumbent – not the price estimated using a regulatory pricing model. Such an approach was consistent with the ACCC’s Draft Statement of Principles for the Regulation of Transmission Revenues (May 1999) in terms of calculating a competitive revenue requirement.
C5 Subsequently, the ACCC commissioned a report from NERA which sought to establish an appropriate MSP HNE price amongst other issues. NERA concluded that an appropriate HNE price was $0.51/GJ compared to the then prevailing MSP tariff of $0.66/GJ. That is, that EAPL’s tariff was some 30% in excess of the HNE price.
C6 This result was at odds with similar analysis by NECG. The two key issues driving this difference were NERA’s treatment of depreciation and use of total Sydney demand (that is the sum of the EGP and MSP volumes) rather than use of current MSP volumes. This approach to estimating demand was justified on the basis that the lowest (transport) cost would be achieved by a single pipeline servicing Sydney and the ACT. This approach fails to recognise that what users want is the lowest cost for a service delivering a range of benefits including the delivered cost of gas and reliability of supply.
C7 That is, the NERA analysis ignored the reality that it was clearly economic for Duke Energy to develop a competing pipeline to provide gas from an alternative source as customers were willing to pay for the benefits associated with security of alternative cheaper paths and the competition benefits of accessing competing gas services.
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MAPS HNE issues C8 In the context of the MAPS where a complete regulatory review has been completed, the existing regulated price when compared to the HNE price does not provide any information with respect to the presence (or misuse) of market power. That is, the MAPS has not had the opportunity to set an unregulated price. However, the HNE price still provides a comparator as to the amount that the price will need to change before it would exceed the upper limit for a competitive market.
C9 Further, as the HNE price reflects the LRMC, it is also likely to provide the baseline for a SSNIP test in establishing the relevant market. That is, the ability to profitably (and sustainably) raise prices materially must be considered in the context of the LRMC (or HNE price) not currently prevailing prices.
Issues in calculating the HNE price C10 The HNE price may be thought of the maximum price that could be charged such that it would not be economically viable to duplicate the asset in order to bypass the existing service provider. As such, critical issues will include, establishing:
• a reasonable risk weighted rate of return;
• demand forecasts over a reasonable time frame;
• the optimum pipeline configuration; and
• the preferred approach to ensuring the return of capital. WACC C11 The weighted average cost of capital (WACC) is the rate of return required to compensate investors for the risks associated with a particular investment. As the WACC is a forward looking concept, it is based on estimated future returns and future expected risks. As such, calculation of the expected return does not lend itself to establishing a single measure of required return but rather a distribution of returns.
C12 Under the Code service providers are faced by a price cap – that is, they must bear the volume risk associated with any variation between demand forecasts and actual demand. This creates greater cash flow volatility than would exist under a pure revenue cap and as such, should be rewarded by a risk premium at the middle to higher end of the range.
C13 Further, gas transmission companies in Australia are generally publicly listed firms traded on the Australian stock market. Investors in such firms will assess the performance of their investments in terms of post tax nominal returns with the simplest formulation being use of a plain vanilla WACC with all tax and dividend imputation allowances included within the cash flows. Using such a framework, a possible range for a reasonable risk premium for a gas transmission business is likely to be in the order of 300 to 400 basis points above the risk free rate. It is argued that proper consideration of the asymmetric risks faced by the MAPS, would suggest that a margin towards the upper end of the range is appropriate,
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but certainly not less than 350 basis points in order to adequately compensate investors.
C14 These risks principally revolve around (or impact on) the demand forecast. While current contracts (on MAPS) are take or pay effectively for the full pipeline capacity, from 2006 this is no longer the case. An indication of possible future demand volatility is provided by the unforeseen reduction in total gas consumption in South Australia in 2003 to only 91 PJ from a previous total of over 100 PJ. This decrease was due to the commissioning of increased electricity interconnection capacity and the associated reduction in gas fired generation in South Australia as increasing amounts of power were provided from Victorian based generators.
Demand forecast C15 The key issues with respect to demand forecasting are uncertainty over volumes (associated with gas supplies) and the question of whether the pipeline is assumed to service the entire market or only a reasonable proportion.
C16 The MAPS is faced with a combination of these issues, for example, total market demand is uncertain due to the impact of electricity generation in terms of whether generation will occur in Victoria (with electricity transmitted via the interconnectors) or generated in South Australia. Additionally, there is the issue of whether the relevant demand is the total SA demand (up to the maximum capacity of the pipeline) or the actual share of total demand forecast to be captured by the MAPS. Clearly, as noted above the issue for users is to secure their desired mix of service characteristics such that the delivered price of gas is minimised. This must include recognition of the benefits of security of supply associated with multiple pipelines and the competitive benefits of alternative gas services.
Optimised replacement cost C17 The asset that a hypothetical new entrant would construct would be based on an optimised design able to satisfy forecast demand over the medium to longer term. In terms of the MAPS, this design has been based the same diameter pipeline but with only three compressors installed as this is considered optimal to satisfy the forecast demand over the next fifteen years.
Depreciation C18 The rate at which an investment is recovered (by way of depreciation) can have a critical impact on project risk. While it can be argued that, technically, the service potential of a gas pipeline declines only slowly (and therefore initial depreciation should be low), this fails to recognise project risk that will operate in the opposite direction encouraging relatively early return of investment to reduce the risk of future asset stranding. The net result is that a straight-line depreciation profile, although largely arbitrary, is likely to be a reasonable compromise between the slow technical decline in service potential (suggesting an annuity depreciation schedule) and the desire to minimise project risk (possible leading to a geometric depreciation schedule).
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C19 The remaining issue becomes one of establishing the period over which straight- line depreciation will be applied. Again, this is likely to be a compromise between the potential engineering life and the desire for some degree of accelerated depreciation.
HNE price assumptions C20 The main assumptions used in calculating the HNE price are presented in the following tables. The first table outlines the general cost of capital assumptions.
HNE cost of capital assumptions Category Value Risk free rate 5.4% Risk Premium 3.5% Post Tax Nominal (Plain Vanilla) WACC 8.9% Real WACC 6.2% Inflation 2.5% Debt Proportion 60% Debt premium 1.20% Debt Cost 6.60% Gamma 0.5 Corporate Tax rate 30%
C21 The next table presents the assumptions underpinning the MAPS HNE price calculation.
MAPS HNE price-modelling assumptions Category Low Demand High Demand Optimised Replacement Cost ($m) 642 642 Weighted Average Asset Life (yrs) 60 60 Annual Operating and Maintenance Costs ($m) 15 15 Firm Contracted Capacity (TJ/day) 194 348 Annualised Contracted Capacity (PJ/yr) 70.8 127.0
HNE price modeling results C22 Before the above assumptions can be applied to calculation of a HNE price, one more critical decision remains, namely, the price profile that is to be applied. At one extreme, an annual price could be calculated taking account of the depreciated replacement cost in that year together with current year demand and operating costs etc. This is likely to result in a relatively volatile price profile, possibly characterised by declining unit tariffs over time. Alternatively, a smoothed price profile may be set aimed at delivering the same investment return on average but possibly with lower early returns and higher later returns. A smoothed profile is likely to be attractive from a marketing perspective in terms of providing a degree of certainty with respect to transport tariffs over time.
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C23 Applying the above assumptions within a post tax nominal modelling framework, suggests a HNE price for the MAPS in 2005 of between 0.92/GJ for a single year to 0.85/GJ for a smoothed 20 year price subject to 95% CPI escalator as outlined in the following table.
MAPS HNE price – Low Demand Component Value Contracted Capacity (TJ/day) 194 2005 single year price ($/GJ) $0.92 Contracted Capacity - Average over 20 years (TJ/day) 194 20 yr real terms smoothed price ($/GJ) Escalated at 95% of CPI $0.85
Sensitivity analysis C24 The above analysis indicated a point estimate for the HNE price given a number of key assumptions. Clearly, the value of any of these assumptions is open to debate and the impact of varying these values is the subject of this sensitivity analysis. The following table indicates the impact on the HNE price of:
• changing the WACC by plus or minus 50 basis points, that is, to 300 400 basis points above the risk free rate;
• an increase (or decrease) in demand (or pipeline throughput) of 10% with no change in capital invested or O&M costs;
• a change in the optimised replacement cost of plus or minus 10%;
• a change in the period over which the capital invested is recovered of plus or minus 20 years (this is the equivalent of either a 40 year or 80 year depreciation period; and
• the impact of combining all of the above factors into a worst (low) or best (high) case scenario.
HNE price sensitivity analysis $/GJ Low 1yr Low 20yr High 1yr High 20yr Base Case Price $0.92 $0.85 $0.92 $0.85 Price - WACC +/- 50bp $0.87 $0.82 $0.96 $0.89 Price - Demand +/- 10% $0.83 $0.78 $1.02 $0.95 Price - ORC +/- 10% $0.85 $0.79 $0.99 $0.92 Price - Life +/- 20 yrs $0.88 $0.83 $0.99 $0.90 Price Range $0.70 $0.67 $1.31 $1.18
C25 The results of this analysis suggest that under a combination of factors minimising the price, it will still be in the order of 75% to 78% of the base case HNE price while a corresponding selection of values maximising the price would see the HNET price of more than 250% of the current price.
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Comparison with current tariffs C26 The current tariffs applying to the MAPS are detailed in the following table.
MAPS current tariffs vs. HNE price Pipeline Tariff MAPS (1 January 2004) $/GJ $0.48 Inflation (@ 95%) to 1 July 2004 1.4% MAPS (1 July 2004) $/GJ $0.49 MAPS 20 Yr HNE Price $0.85 MAPS current price as % of HNE price 58%
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ATTACHMENT D
Workable Competition in the Duopoly Airline Market
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Workable Competition in the Duopoly Airline Market D1 The most obvious case of workable competition in the presence of a duopoly market structure in the Australian context is the airline industry, which has historically been characterised by two major participants with occasional entry by a third party. However, it is clearly apparent that even this duopoly structure has delivered measurable benefits to consumers in terms of increased airline operating efficiency and lower prices.
Background D2 Before 1990, the Australian domestic aviation industry was regulated as a duopoly market under the two airlines policy. For over 50 years the industry was dominated by two major airlines. After 1990, deregulation was introduced which enabled new entrants to enter the market. The barriers to entry proved significant for the initial entrants Compass and Compass Mark 2 who both failed after introducing services in 1990 and 1992 respectively.
D3 Further deregulation saw foreign ownership rules change to allow 100 percent foreign ownership of Australian domestic airlines. Following the change, Virgin Blue entered the market in August 2000. The failure of previous entrants created pessimistic views of Virgin Blue’s prospects. However, in this instance, it was one of the incumbent major airlines, Ansett, which collapsed in September 2001.
D4 Before Ansett’s collapse, the domestic airline industry was operating at record levels boasting 3.0 million passengers and 3.2 billion revenue passenger kilometres (RPKs) for the month of July 2001. The Ansett collapse coupled with the terrorist attacks of September 11 created damaging uncertainty in the industry. By October, normally Australian airlines busiest month, operating levels had reduced by more than 20 percent compared to July 2001.
D5 The surviving airlines immediately increased capacity on previous Ansett routes. Qantas’ capacity increased from 1.9 billion available seat kilometres (ASKs) in August 2001 to 2.4 billion in November 2001 (representing a 27.6 percent increase). Over the same period, Virgin Blue’s capacity increased from 263 million ASKs to 318 million (representing a 20.9 percent increase).
D6 Since the low point following the collapse of Ansett, the Australian domestic airline industry has sustained an unbroken expansionary period. The sustained growth has taken operating levels beyond the records reached prior to the Ansett collapse. In the year to July 2004, 36.9 million passengers were carried on domestic and regional airlines (representing a 7 percent increase from the year to July 2001). This increase can be seen in the following figure.
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Domestic and regional passengers (annual)
40 38 36 34 32 30 28 26 24 Millions of passengers 22 20 Jan-00 Jul-00 Jan-01 Jul-01 Jan-02 Jul-02 Jan-03 Jul-03 Jan-04 Jul-04 Date
Note: Regional data components includes BTRE estimates Data source: BTRE Transport Economics, cited in BTRE (2004).
D7 The Australian domestic airline industry is currently operating at record levels. Between September 2003 and July 2004 the industry recorded its seven busiest months ever. In July 2004, a record 3.44 million passengers were carried on domestic routes (representing a 12.7 percent increase from July 2001).
D8 BTRE (2004) reports that aircraft productivity is significantly higher than in the pre-Ansett (collapse) period. Load factors have recovered and strengthened after the collapse of Ansett. Load factors exceeded 80% for several months in late 2003. In May 2004, load factors fell to 74.9 percent following the introduction of additional capacity by Virgin Blue and the new Qantas low-cost subsidiary, Jetstar. However, by July 2004, load factors returned to above 80 percent.
Effects on competition D9 There is no doubt that the deregulation of the airline market and the motivation of the recent duopoly structure following the collapse of Ansett has left the Australian domestic airline sector in a stronger, more competitive position than ever before. Australia now has tow competing service models, firstly a full service model (Qantas) and secondly a discount (no frills) model originally provided by Virgin Blue and more recently by Qantas’ subsidiary Jetstar.
D10 Three years ago, there were fears that Qantas would gain monopoly control in the market. Presently, Virgin Blue has continued to expand its services and market share. While continuing to provide discount airline services, Virgin Blue has expanded its model to provide some business and other premium passenger services (such as airport lounges) therefore increasing competition for the services provided by Qantas. Similarly, Qantas has increased the services it provides to compete with Virgin Blue, by entering the discount service market with the launch of Jetstar in May 2004. This has allowed Qantas to supply
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differentiated products to the market. The increased competition has provided benefits to consumers in both the business and discount services.
D11 The benefits are clearly apparent in the following figure, which shows the reduction in prices offered to consumers of discount services. The time series data is of domestic air fare indices based on the lowest business, economy and discount airfares available through the Sabre Pacific Computer Reservation System. The indices have a base period of November 2000 and include taxes and charges that are included as part of the airfare (security, certain airport charges and GST).44
Real domestic airline ticket prices
120.0
100.0
80.0
60.0
40.0
Price Indeces (Nov-00=100) 20.0
0.0 Jan-00 Jul-00 Jan-01 Jul-01 Jan-02 Jul-02 Jan-03 Jul-03 Jan-04 Jul-04
Business Economy Discount
a Data source: BTRE Transport Statistics; SABRE Computer Reservation System (Disclaimer applies).
D12 Since the entry of Virgin Blue in August 2000, while volatile, discount airfares have nevertheless continued to trend down. In the most recent month for which data was available (October 2004), discount ticket prices had reduced by approximately 48% compared to August 2000. At their lowest point (in July 2004), discount airfares had fallen by more than 55% since the entry of Virgin Blue.
D13 In contrast, real terms economy fares have remained virtually static over between August 2000 and October 2004 with an increase of 0.3% while business class airfares have increased by some 7.8%.
44 The fall in prices is more telling of workable competition when rising jet fuel prices are considered.
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