Network Pricing, Voll and Interconnection in the NEM
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Network Pricing, VoLL and Interconnection in the NEM
Conference
30 September 1999
Interconnection issues
in the NEM
Allan Asher
Deputy Chairman
Australian Competition and Consumer Commission
1. Introduction
(Slide 2)
There is a current move in the NEM away from the traditional model of central planning for networks towards market provision of network services. This raises several issues, including whether networks should be regulated.
Today I want to raise these and other emerging interconnector issues that will need to be debated in the industry, if an effective and efficient framework for the operation of regulated and non-regulated interconnectors is to be developed. The views I am expressing today do not in any way prejudge the outcome of the market network service provider Code changes before the Commission for authorisation and access code variation – I am merely setting out some of the issues that the industry will need to consider in the coming months.
I will also give an outline of the major issues that are facing the Commission in developing its regulatory principles for the regulation of transmission revenues, since these principles also apply to regulated interconnectors.
2.History of network planning and regulation
(Slide 3)
The Australian electricity supply industry has traditionally consisted of state based vertically integrated public utilities with little interconnection between the jurisdictions.
Another historical feature of the Australian electricity industry is that governments have considered networks to be natural monopolies, which require regulation to prevent the potential abuse of market power by network owners/ operators. This has lead to the inclusion of interconnector assets into the relevant transmission company’s regulatory asset base and therefore TUoS charges. There has also been an emphasis on regulated network solutions, rather than non-regulated or market network services.
In 1996, the Productivity Commission’s international benchmarking report argued that an interconnected electricity grid, which improves opportunities for power exchanges between the States, would allow electricity generators to make better use of capital assets and thereby reduce excess capacity and improve productivity.
(Slide 4)
In the original authorisation of the National Electricity Code (December 1997), the Commission stated that there are four main sources of economic benefit from an interconnected wholesale electricity market. Firstly, interconnection will lead to greater competition between suppliers. Secondly, it will lead to the development of market based incentives, which will put pressure on electricity producers to reduce costs and use their assets more efficiently. Thirdly, an interconnected wholesale market will lead to the deferral of new generation plant investment because of the potential to share reserve capacity. Lastly, it will lead to increased flexibility and reduced costs as a result of better utilisation of the mix of generating technologies.
3.Future options for network planning and operation
These traditional views are now changing, raising questions about whether all networks should be regulated. Some of the options that are emerging are the establishment of market network service providers (also called entrepreneurial interconnectors); and hybrid interconnectors, which comprise regulated and nonregulated components.
3.1Market Network Service Providers
(Slide 5)
NECA has submitted Code changes that allow for the operation of market network service providers to the Commission for authorisation and for acceptance as a variation to the NEM access code. NECA has also submitted an application for interim authorisation on the basis that it would provide some protection for imminent projects such as Directlink and Basslink that are in vital stages of their auctioning and bidding processes respectively. The Commission is currently assessing the application for interim authorisation of the market network service provider Code changes and will make a decision in the next couple of weeks.
The Commission will conduct a full assessment of these Code changes over the coming months and will consider whether it is necessary to impose any conditions on the authorisation in its draft determination. The Commission is aiming to release a draft determination on the market network service provider Code changes and the network pricing Code changes in December. Parties will then have the opportunity to provide further submissions and may request a predecision conference before the final determination is released.
There are several new issues that have been raised by the introduction of market network service providers (MNSPs) into the NEM. The major issues raised in submissions to the Commission’s authorisation and access assessments were:
- whether market network network services will deliver benefits to customers, such as lower prices, or whether the benefits will all be captured by the MNSP?
- whether market network services will deliver an optimal level of interconnector capacity?
- whether system security obligations be placed on MNSPs?
- to what extent should MNSPs be required to pay TUoS?
As part of NECA’s review into the integration of energy markets and network services, NECA is examining the appropriateness of a nodal pricing regime. If the market decides to move to either a full nodal pricing regime or even a modified zonal model, with more zones than at present, then it will be important to consider how well the entrepreneurial interconnector model fits with these options. One particular issue to consider is how the ability for market network service providers to control usage of their interconnector sits alongside a nodal pricing regime?
Some participants in the industry have argued that the provisions for entrepreneurial interconnectors should be broadened to also apply to other network elements. In considering this issue the industry needs to carefully consider the implications of an entrepreneurial interconnector that has the ability to withdraw capacity and is part of the meshed transmission network.
Another issue regarding MNSPs is the appropriate form of their access undertakings. Given that MNSPs will not earn their revenue through TUoS charges, they are exempt from complying with the network pricing provisions in Chapter 6 of the Code. However, according to the Trade Practices Act an acceptable access undertaking should include details of the terms and conditions used to allocate the MNSP’s capacity. An undertaking should also outline the MNSP’s approach for dealing with future access applications once the initial capacity is fully allocated.
3.2Hybrid Interconnectors
(Slide 6)
NECA is in the process of developing rules for the operation of hybrid interconnectors, though these have not yet come before the Commission for authorisation or variation of the access code. There are several circumstances in which a hybrid interconnector could be envisaged; for example an entrepreneur may wish to upgrade an existing regulated link. This situation occurred with the interconnector between Scotland and the England and Wales pool. ScottishPower built the original interconnector with a capacity of 850 MW. These assets and associated costs were included in the price control determination for ScottishPower’s transmission business because the interconnector was deemed to have system security benefits for Scottish customers. The interconnector was subsequently upgraded to a capacity of 2,200 MW, however this was funded by contracts between ScottishPower and the users of the interconnector, rather than recovered through TUOS charges.
One important issue that will need to be addressed when developing rules for the operation of hybrid interconnectors is to ensure that there are adequate ringfencing provisions in place to prevent cost shifting between the regulated and unregulated components of the business. Some other issues that will need to be considered are:
- How would financial hedges be sold for hybrid interconnectors?
- Should the hedges for the regulated and unregulated components of the business be auctioned together?
- Should any outages or constraints on interconnector capacity affect either the regulated or the unregulated parts of the business, or should the impact be prorated between the components? and
- How should ancillary services be split between the regulated and unregulated components?
All of these are important issues that the industry must resolve when establishing rules for the operation of hybrid interconnectors.
4.The test for regulated network augmentations
(Slide 7)
Chapter 5 of the Code establishes several avenues for planning and undertaking interconnection, including regulated and unregulated options. Regulated assets earn a regulated return in accordance with chapter 6 of the Code, while unregulated assets earn a return through transactions in the market. Chapter 5 describes decision processes and criteria, under which interconnectors may become part of a transmission NSP’s regulated asset base. In essence, an augmentation may receive approval to enter the regulated asset base (before it is built) if it passes a “Customer benefits test” administered by NEMMCO.
The rules governing interconnection came into the spotlight when NEMMCO rejected the application for the proposed South Australia - New South Wales interconnector to be a regulated interconnector. Indeed, NEMMCO found the Customer benefits test to be highly volatile, which would make it difficult for any proposed inter-regional augmentation to satisfy the criterion.
On the basis of these concerns, in late July NECA lodged an application for authorisation of a number of Code changes. Included in this application, was the proposal to replace the existing Customer benefits test with a regulatory test to be defined by the Commission. Public comments to the Commission were supportive of this proposal.
(Slide 8)
At the Commission meeting last week, the Commission made a draft determination to accept the Code changes subject to two minor conditions. The first condition is that there be changes to the language that requires the Commission to promulgate the regulatory test and to assess asset values on a basis consistent with that regulatory test. The purpose of this condition is to ensure that the Commission’s obligations deriving from these Code changes are consistent with the Commission’s broader regulatory obligations as contained in Chapter6 of the Code.
The second condition is that when using the regulatory test, a market network services option should be included as one of the alternatives to the network options under consideration. This would place the market network service option on the same basis as that currently held by generation and demand side options.
A copy of the draft determination is available from the Commission’s web site. If requested to do so by an interested party, the Commission will hold a predecision conference in late October before releasing the final determination.
In addition to assessing the Code changes, the Commission has also developed a draft of the regulatory test. This draft of the regulatory test builds on the earlier report for the Commission by Ernst & Young and the subsequent staff paper that was released in April.
Consistent with the earlier staff paper, the current draft of the regulatory test proposes replacing the current Customer benefits test with a market benefits test. This revised test is more consistent with the usual approach for assessing net public benefits and includes those benefits and costs that accrue to both consumers and producers of electricity. Moreover, by focusing on a least cost approach, the test attempts to avoid the problems of including into the assessment of network options any non-competitive price behaviour that may occur in the generation sector. By requiring the use of commercial discount rates, the draft test attempts to ensure that network options do not possess a competitive advantage over other generation or demand side alternatives. Finally, the test also provides for the inclusion of environmental costs or benefits as part of any assessment of a network investment.
However, on the basis of the most recent submissions, the draft test includes a number of changes from the earlier staff paper. First, the Commission has expanded the provisions relating to environmental costs and benefits by requiring the inclusion of any environmental taxes or subsidies into the analysis of new network investments. Second, the Commission has attempted to clarify the extent to which costs and benefits are included in the analysis. Finally, the Commission has decided to set aside the earlier staff proposal to include a market failure component to the test. Interested parties have indicated that this market failure test could be easily gamed at the cost of an efficient outcome. Nevertheless, the Commission has required that unregulated network options be considered as part of the assessment of a regulated network investment.
The revised draft of the regulatory test is also available from the Commission’s web site. Interested parties have a further opportunity to comment on the test, prior to its promulgation once the Code changes have been finalised.
Several industry participants have indicated that the Commission should be the body that applies the regulatory test rather than the IRPC, as proposed by NECA. The Commission can see that there are some symmetries between this role and its regulatory role of optimising transmission network assets as part of the revenue determination process, however further thought will need to be given to this issue.
5.Draft regulatory Principles
If interconnectors pass the regulatory test than they will be regulated on the same basis as other elements of the regulated transmission networks. As such, the principles developed by the Commission for the regulation of transmission revenues will also apply to regulated interconnectors. In May this year, the Commission released the Draft Principles for the Regulation of Transmission Revenues (Draft Regulatory Principles) which establishes guidelines as to how the Commission will regulate the industry. The Draft Regulatory Principles is available from the Commission’s internet site.
The transmission regulation framework outlined in the Draft Regulatory Principles is a building block approach based on forecasts of cost of service over the regulatory period. The building block approach calculates the Aggregate Annual Revenue Requirement as the sum of the return on capital, the return of capital, and operating and maintenance expenditure.
While the assessment of operating and maintenance expenditures is relatively straight forward, assessment of the other elements is not. Determining these elements of the accrual building block raises significant issues with respect to providing NSPs with a fair and reasonable return, while at the same time promoting economic efficiency and an objective, transparent regulatory process.
It is therefore imperative that the regulator comes up with accurate revenue cap decisions. The Commission implements the following procedures to ensure this is the case. First, the Commission conducts a transparent and open process in the determination of revenue caps for transmission NSPs. The Commission invites stakeholders to put information forward to try to persuade the regulator and also consults stakeholders to understand the implications of its regulatory decisions. Second, the Commission attempts to gather the most accurate financial data it can in determining regulatory parameters.
5.1Determining a fair rate of return on the asset base
(Slide 9)
In determining a rate of return, the Code requires the Commission to consider the weighted average cost of capital (WACC) for each transmission network. Given the capital-intensive nature of electricity network businesses, the return on capital component of the regulated revenue could account for 50 per cent or more of annual aggregate revenue. As relatively small changes to the rate of return can have a significant impact on the total revenue requirement and ultimately end user prices, it is important that the regulator sets the rate of return at a level which reflects a commercial return for the regulated businesses.
Setting a rate of return below the cost of funds in the market could make continued investment in developing the network difficult or unattractive for the owner. This would create pressure for the regulated business to reduce maintenance and capital expenditure below optimum levels and undermine the quality of service offered to users. Conversely, if the regulator set the rate of return too high, the regulated businesses would earn a return in excess of their cost of capital. This would distort price signals to consumers and investors, resulting in a misallocation of resources and sub-optimal economic outcomes.
In the Draft Regulatory Principles, the Commission has adopted a nominal posttax WACC approach. In addition, the Commission will set the WACC on the basis of financial market benchmarks, taking into account the level of commercial risk involved in establishing the transmission infrastructure.
5.2Return of capital
(Slide 10)
To encourage continued investment in natural monopoly industries, investors will require an assurance that they will earn a reasonable (risk adjusted) return on their investment capital, as well as the return of capital, provided the market continues to value the services produced with that capital.