Australia: Regulatory clearances for bidders in the Australian electricity market

Key regulatory clearances required by bidders may include foreign investment approvals and competition clearances. Foreign investment approvals are straightforward and rarely withheld, but are a necessary formality. Competition clearances may be important if a bidder, or any participants in a bidding consortium, have existing electricity operations in Australia, whether in generation, transmission, distribution or retail.

The ACCC may be concerned if the acquisition of shares or assets of the Project Company could result in a substantial lessening of competition in any market in Australia. Concerns could arise, for example, if a potential investor was an electricity generator or retailer. In such circumstances, the ACCC may be concerned at the potential for a vertically integrated transmission or distribution network provider to discriminate in favour of its own operations.

However, the potential for investment of a generator or retailer in vertical integration will not necessarily be fatal to ACCC clearance of an asset purchase. The ACCC's reaction would turn on the circumstances of the case. The investor might be considered to have an immaterial shareholding or a role that gives it no practical influence. It may in any case be possible to provide a voluntary undertaking to the ACCC that addresses adequately any competition concerns.

For example, an undertaking could be provided that competitors to the generator/retailer would be able to connect to the transmission or distribution network on a non-discriminatory basis. Also, requirements that these aspects of the businesses be ring-fenced may assist. Indeed, ring fencing restrictions already exist under the National Electricity Law and may alleviate some of these issues.

If competition issues were identified, the strategy and timing for any approach to the ACCC would need to be carefully considered. Generally, the ACCC is not willing to provide clearance without undertaking public market inquiries. If confidentiality issues preclude inquiries prior to bid submission, the bid may need to be made conditional on any ACCC clearance.

Regulation of TransGrid as a transmission network

As a transmission network, TransGrid is subject to price and access regulation under the National Electricity Rules. The terms on which transmission networks offers transmission services to its customers (largely distributors) must be fair and reasonable. The Rules provide for commercial arbitration in the event of any network access dispute.

Under the Rules, the services provided by transmission networks are categorised into two baskets: "prescribed control services" (which comprise most core transmission services) and "negotiated services". The charges for prescribed control services are heavily regulated, whereas the charges for negotiated services are negotiated and need only be based on the costs of providing those services (determined in accordance with a cost allocation methodology approved by the AER).

In determining the pricing of prescribed control services, the Australian Energy Regulator (AER) must make a "transmission determination", typically for a period of 5 years. This period is known as the "regulatory control period". The Rules permit the AER to apply a revenue cap to transmission businesses. The AER has historically applied to TransGrid a revenue cap consistent with the approach adopted for other transmission networks in the NEM, and will almost certainly continue to do so.

In determining the level of the revenue cap for a transmission network, the AER utilises the building block model (BBM) and regulated asset base (RAB), as discussed in further detail below. Transmission networks are required to have an approved pricing methodology that allocates that revenue across the relevant categories of prescribed control services, thereby determining tariff levels and the tariff structure.

Specifically, transmission networks must seek approval by the AER, via the transmission determination, for a pricing methodology for an entire regulatory control period. The AER must approve the pricing methodology if it does not exceed the revenue cap and meets various criteria, including consistency with pricing principles in the Rules. The pricing principles identify the manner in which costs are to be attributed across the different categories of prescribed control services. The pricing principles also identify the permitted fixed and variable tariff structures.

During the regulatory control period, the transmission network must publish annual prices that are determined in accordance with the approved pricing methodology. To date, transmission charges have comprised a fixed daily price component and variable demand/consumption component.

Regulation of Networks NSW as distribution networks

While the manner in which the distribution networks of Networks NSW are regulated is similar to transmission networks, there are some important nuances under the National Electricity Rules.

Under the Rules, the services provided by distribution networks are categorised into three baskets, as shown in the diagram below. "Direct control services" comprise most core distribution services. "Negotiated services" largely comprise site-specific services. "Unregulated services" largely comprise ancillary services supplied in contestable circumstances or that do not otherwise need to be regulated.

Unregulated services are not subject to access or price regulation under the National Electricity Rules. However, direct control services and negotiated services are subject to both price and access regulation. The terms of access to direct control services are specified in the Rules and include connection and system security requirements. The terms of access to negotiated services must be negotiated by a distribution network in accordance with a negotiating framework that has been approved by the AER.

The charges for direct control services are heavily regulated, whereas the charges for negotiated services are negotiated and need only be based on the costs of providing those services (determined in accordance with a cost allocation method approved by the AER). Importantly, the level of regulation that may be applied by the AER to distribution networks for direct control services is greater than the level of regulation that may be applied by the AER to transmission networks in relation to prescribed control services. This regulation is referred to in the Rules as "control mechanisms".

In determining the pricing of direct control services, the AER must make a "distribution determination", typically for a period of 5 years. Again, this period is known as the "regulatory control period". The Rules permit the AER to impose controls over the prices of direct control services, or apply a revenue cap, or both. The control mechanisms available to the AER are significant, including price caps, price schedules and revenue caps. The AER has historically applied revenue caps and annual price controls to the distribution networks in Networks NSW, consistent with the approach adopted for other distribution networks in the NEM, and will almost certainly continue to do so.

In determining the level of the revenue cap for a distribution network, the AER utilises the building block model (BBM) and regulated asset base (RAB), as discussed in further detail below.

Unlike transmission networks, distribution networks are required to submit an annual pricing proposal to the AER that sets out the various tariffs and the tariff structure proposed. The AER must approve the pricing if it does not exceed the revenue cap and meets various criteria, including consistency with detailed pricing principles in the Rules. Among other matters, the pricing principles allocate customers into tariff classes and apply charging parameters to each class. The distribution network is also required to publish on its website a statement of expected price trends over the full regulatory control period.

To date, customer charges for distribution have generally comprised three key components:

• a network access charge per day per connection (c/connection/day);
• a electricity usage charge (c/kWh); and
• a capacity charge per kiloWatt or kilovoltAmp, per day (c/kW/day or c/kVA/day) – namely a charge based on a customer's maximum demand.

The Building Block Model (BBM) and Regulated Asset Base (RAB)

In order to determine the revenue cap for distribution and transmission networks, the AER makes revenue determinations that are guided by various statutory criteria. The National Electricity Rules prescribe a cost-based pricing methodology for those determinations, known as the "building block model" or "BBM". The BBM enables an "annual revenue requirement" (or "maximum allowable revenue") to be determined for each network business in the form of a revenue cap for each regulatory control period.

The BBM methodology is applied in Australia for the regulation of a wide range of infrastructure. The objective of the BBM is to deliver an NPV=0 outcome so that an operator only recovers its efficient costs plus a risk-adjusted return equivalent to its weighted average cost of capital (WACC).

The first step in initial application of the BBM was to historically determine the 'regulated asset base' (RAB) for each business. The initial RAB comprised the value of the sunk network assets. Each year, that 'locked in' RAB has been 'rolled forward' via annual adjustments that reflect the net effect of depreciation and asset disposals (both as a RAB reduction) and capital expenditure and inflation (both as a RAB addition). The RAB is therefore a snapshot of the regulatory valuation of the assets of an electricity network.

Under the BBM, the Maximum Allowable Revenue (MAR) of the business each year is equal to the sum of the underlying five "building blocks", which consist of the return on capital, the return of capital (also known as depreciation), the forecast operating expenditure (OPEX), corporate income taxes (net of imputation credits), and adjustments for increments or decrements from an efficiency incentive scheme.

The largest 'building block' is the return on capital, which may account for up to two-thirds of the MAR. The 'building block' methodology is illustrated by the following diagram:

Unfortunately, the BBM model may create incentives for regulated business to inflate the RAB by undertaking excessive capital expenditure (CAPEX), a practice known colloquially as 'gold plating'. The businesses' ability to recover CAPEX in the form of higher prices to consumers, has reduced incentives to minimize CAPEX on 'gold plating'. Public concerns in Australia have therefore led to revisions to the BBM.

Recent reforms to the National Electricity Rules have introduced disincentives to 'gold plating', including by applying an 'efficiency' test to CAPEX. Three mechanisms now achieve this:

• Ex-post reviews: The AER may undertake ex-post reviews of CAPEX to prevent the inclusion of inefficiently incurred CAPEX in the RAB. In doing so, the AER will consider:
• • the efficient costs of achieving the 'capital expenditure objectives'(i.e., of meeting and managing demand, maintaining quality, reliability and security, and complying with regulatory obligations);
  • the costs that a prudent operator would require to achieve those objectives; and
  • a realistic expectation of the demand forecast and cost inputs to achieve those objectives.
• Ex ante incentives: The AER has developed a CAPEX incentives guideline and efficiency benefit sharing scheme to encourage efficiencies to be realised and shared with consumers.
• Forecasting guidelines: The AER has developed an Expenditure Forecast Assessment Guideline that must be complied with by networks for the provision of accurate forecasts of OPEX and CAPEX.

Application of network price regulation in NSW

The amendments to the National Electricity Rules identified above take effect from 1 July 2015. However, in the case of NSW, the previous 5 year regulatory control period expired on 30 June 2014. Accordingly, an adjustment process has been adopted in which an interim revenue cap applies for the 'transitional year' period from 1 July 2014 to 30 June 2015, known as the 'placeholder revenue allowance'.

Specifically, a full determination will be made by 30 April 2015 for the whole regulatory control period (1 July 2014 to 30 June 2019). In the full determination, the AER will reconcile any difference between the placeholder revenue allowance for the transitional year and the final MAR for that transitional year established by the full determination.

Importantly, each of the network businesses in NSW has already lodged its proposals for the full period to the AER. The expected timeline is as follows:

Accordingly, subject to any appeal of the AER's decision to the Australian Competition Tribunal (which could take 6 months), the financial parameters for the various electricity networks in NSW to June 2019 should to be known before or during the expression of interest period for the privatisation.

As at June 2014, the AER has determined the following outcomes for the relevant NSW networks for the transitional period:

The table above illustrates a couple of important issues for the current regulatory control period that will be relevant for bidders:

• Reduction in WACC: The WACC has significantly reduced in the current regulatory control period relative to the previous regulatory control period leading to a reduced return on capital and a lower revenue cap. Recent developments in the capital markets have lowered capital costs. Regulatory determinations made since 2012 reflect recent reductions in the risk free rate and market and debt risk premiums that have lowered the cost of capital. The overall cost of capital in determinations made in 2013 was 7–7.5% compared with up to 10.4% in 2010.
• Declining electricity demand: Declining electricity demand has led to surplus generation capacity in the NEM and has delayed the need to invest in electricity networks, resulting in deferral of CAPEX. Declining demand also affects electricity prices for network businesses to the extent that tariffs are variable with volume. All things being equal, a reduction in volume would tend to lead to an increase in the tariff for the variable component of network charges in order to recover the same revenue. In the context of the privatisation, the Government has already indicated it will seek commitments on pricing.

We are happy to discuss these and other issues in further detail.

Network extensions and enhancements during a 99 year lease

The adoption of a 99 year lease structure by the NSW Government does create potential complications for bidders in circumstances where network enhancements and extensions are required. Under the lease structure, the NSW Government will remain as asset owner and lessor, whereas the successful bidder will be the lessee and operator. This begs a series of questions:

• who should pay for the CAPEX, particularly network extensions and enhancements;
• if the successful bidder is required to pay for the CAPEX, who will then own the assets;
• if assets are required to be transferred to the NSW Government, will any compensation be paid;
• what taxation consequences flow from such transfers for potential bidders;
• if CAPEX is required in the context of a joint venture with the NSW Government, will the NSW Government be willing to share in the CAPEX and, if not, what adjustment to relative shareholdings should occur?

Each of these issues is an important point that will need to be worked through carefully in the coming months in the context of the scoping study.

However, these issues are not unique to the proposed NSW electricity network privatisation. There are many precedents from Australia and overseas where 99 year leases have been granted in circumstances were ongoing capital expenditure is required and further substantial asset enhancements have occurred. The privatisation of ETSA in South Australia and the rail privatisation in Queensland, for example, both provides insights into a potential structure that could be adopted in NSW.

In Queensland, the Queensland Government sold a 99-year lease of the central Queensland coal network rail system to Aurizon. Under the Queensland model, if Aurizon wishes to extend or enhance its rail network it must meet various criteria and obtain State Government approval. To avoid a charge of stamp duty to Aurizon, the State Government would directly acquire any necessary land. Aurizon would then build the necessary rail infrastructure on the land at its cost and then immediately transfer the rail infrastructure to the Queensland Government. The infrastructure and land would then be leased by the Queensland Government back to Aurizon as part of the 99 year lease.

In SA, the lessee (SA Power Networks) of the 200 year lease was responsible for all costs, expenses and liabilities associated with the leased network assets and was responsible for all maintenance, upgrading and replacement of those assets. Again, capital expenditure by the lessee therefore resulted in the creation of assets that were owned by the lessor (SA Government) and leased back to the lessee.

In the SA example, the 200 year lease of land involves periodic rental payments through the term of the lease, raising potential tax treatment issues for any bidder. However, the bidder in SA opted to pre-pay all of the rental payments for the 200 year lease of the network assets in the form of the privatisation price.

Other issues in due diligence

As part of due diligence, any bidder will need to understand the upside and downside risks associated with the various cash flows generated by each electricity network under the proposed privatisation structure. As identified above, some of these issues are not necessarily straightforward and will be heavily affected by the regulatory regime as well as any obligations imposed on bidders relating to electricity pricing.

An important issue in due diligence may also involve the capital structure of the relevant businesses and the extent to which gearing levels can be changed, particularly in circumstances where the NSW Government still owns a substantial interest. The capital structure will have a direct impact on valuation.

Other issues for due diligence include the potential impact of new technologies on distribution businesses. For example, the NEM currently has some 3,500MW of solar power generated by consumers and that rate is continuing to increase, altering load profiles and resulting in re-injection of power via distributed generation. In the coming decades, we can also expect the widespread deployment of batteries and electric cars to have a dramatic on load profiles in distribution networks.

Other potential issues for due diligence include, for example:

• property issues, including easement and native title issues;
• insurance and litigation risks, particularly in the context of recent litigation involving damage caused by fires;
• employee and industrial relations issues, including such matters as superannuation entitlements;
• occupational health and safety issues, particularly given the transmission of electricity is an inherently hazardous operation;
• information technology issues.

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