Introduction

In June 2014, the State Government in New South Wales (NSW) announced that it intends to privatise the NSW electricity networks. This briefing note sets out the likely structure of the privatisation and identifies some key issues.

The NSW electricity networks are currently 100% state-owned and comprise:

TransGrid, an electricity transmission operator with a regulated asset base of AUD 6.1 billion that is expected to realise AUD 845 million in annual revenue next financial year. TransGrid owns roughly 14,000 km of transmission lines in NSW and transmits 71 GWh of electricity per annum over those lines. Networks NSW, which comprises the following three electricity distribution businesses with a common CEO and common senior management:

  • AusGrid, an electricity distributor supplying 1.6 million retail electricity consumers in the Sydney, Central Coast, Hunter and Newcastle regions of NSW. AusGrid has a regulated asset base of AUD 14.6 billion across its distribution assets that is expected to realise some AUD 2.21 billion in revenue in the 2014/15 financial year. AusGrid owns roughly 42,000 km of distribution lines and is capable of meeting peak demand of 5,149 MW;
  • Endeavour Energy, an electricity distributor supplying 883,000 retail electricity consumers in western Sydney and the Illawarra regions of NSW. Endeavour has a regulated asset base of AUD 5.6 billion across its distribution assets that is expected to realise some AUD 949 million billion in revenue in the 2014/15 financial year. Endeavour owns roughly 34,500 km of distribution lines and is capable of meeting peak demand of 3,236 MW; and
  • Essential Energy, an electricity distributor supplying 803,000 retail customers in regional NSW. Essential has a regulated asset base of AUD 6.9 billion across its distribution assets that is expected to realise some AUD 1.29 billion in revenue in the 2014/15 financial year. Essential owns roughly 191,000 km of distribution lines and is capable of meeting peak demand of 2,185 MW.

However, the Government has indicated that it does not intend to privatise Essential Energy.

The role of electricity networks in the NEM

Electricity networks transport power from generators to customers. Transmission networks (e.g., TransGrid) transport power over long distances at high voltages, linking generators to distribution load centres. Distribution networks (e.g., Networks NSW) then reticulate electricity from the transmission network through urban and regional areas at lower voltages to provide electricity to customers.

In Australia, the National Electricity Market (NEM) is a wholesale market comprising some 300 generators that collectively sell some 200 TWh of electricity annually in eastern and southern Australia. The principal customers of those generators are energy retailers. The energy retailers bundle electricity with network services for sale to some 9.3 million residential, commercial and industrial energy users. The NEM covers six Australian jurisdictions — Queensland, NSW, the Australian Capital Territory, Victoria, South Australia and Tasmania.

Electricity is carried within the geographic area of the NEM via five State-based transmission networks, physically linked by cross-border interconnectors and servicing 13 distribution networks. In geographic span, the NEM is one of the world’s longest continuous AC systems, covering a distance of some 4,500 kilometres.

Because energy networks are capital intensive and incur declining average costs as output increases, network services in a particular geographic area can be most efficiently provided by a single supplier, leading to a natural monopoly industry structure. Within the NEM, each transmission and distribution network has a monopoly in its particular geographic area. As such, the electricity networks in the NEM are regulated under Australia’s National Electricity Law to manage the risk of monopoly pricing and to encourage efficient investment in infrastructure. The National Electricity Law is explained later in this briefing note.

Political context to the privatisation

A number of other States in Australia privatised their electricity assets at an early stage, commencing with Victoria’s privatisation of the Loy Yang B power station in 1992. However, the privatisation of electricity assets in NSW was politically controversial for the NSW Labor Party in its role in Government over the 16 year period from 1995 to 2011. A number of proposals for NSW electricity privatisation did not proceed during that period, including under Premier Bob Carr in 1997 and Premier Morris Iemma in 2008.

Ultimately, a first phase of privatisation was initiated by Premier Kristina Keneally in NSW in 2008. The first phase involved the sale of NSW electricity retail businesses, development sites and electricity generation output contracts (known as the “GenTrader” contracts). The Government realised AUD 5.3 billion in sale proceeds.

With a change in NSW Government to a Liberal/National Coalition in March 2011, Premier Barry O’Farell initiated a second phase of privatisation. The second phase involved the sale of the electricity generation businesses. As at June 2014, aspects of this sale are still occurring, including a successful application for authorisation by AGL Energy to the Australian Competition Tribunal to acquire Macquarie Generation.

In May 2012, the NSW Government announced that as part of its policy to put downward pressure on electricity prices a common chairman, board and CEO would be appointed to the State’s electricity distribution network businesses from 1 July 2012. As a result Ausgrid, Endeavour Energy and Essential Energy were aggregated to form Networks NSW in a move viewed as a prelude to privatisation.

On 10 June 2014, Premiere Mike Baird announced the third phase of privatisation, the subject of this briefing note, as part of a ‘Rebuild NSW’ policy that the Liberal/National Coalition will take to the 2015 State election. Given political concerns, an outright sale of the electricity networks is not contemplated. Instead, the privatisation will occur via the sale of 99 year ‘partial leases’. The Government will maintain ownership of 100% of Essential Energy and will also maintain an average ownership of 51% across all four electricity networks.

Timing for the privatisation

Importantly, Premier Mike Baird has announced the privatisation of the electricity networks in the form of a policy commitment that he will take to the next NSW State election scheduled for 28 March 2015. The formal process for the privatisation will therefore not commence unless and until the Liberal/National Coalition is returned as the NSW Government on that date.

As at June 2014, the Labor Party has indicated that it will not proceed with the privatisation if it wins the NSW State election in March 2015.

Notwithstanding that the privatisation is contingent on the election, the NSW Government is currently undertaking preparatory work for the privatisation, including the appointment of financial and legal advisors. The preparatory work will likely involve the completion of a scoping study and an initial vendor due diligence. The scoping study is likely to make a series of recommendations regarding the structuring of the privatisation and implementing legislation.

We expect the scoping study to be provided to the NSW Government in late 2014.

Transaction structure – ownership permutations

As at June 2014, the structure for the transaction has not been determined. We have speculated below on some possible structuring options.

Importantly, the NSW Government has announced that it intends to maintain an overall 51% ownership level across all four electricity businesses, including maintaining 100% ownership of Essential Energy. The NSW Government has not yet identified how it will apply the 51% ownership threshold in practice. Some public statements, for example, refer to the ownership level as “51% of total electricity network assets”.

Given that Ausgrid is the most valuable business, the Government may prefer to privatise a full 100% of that business under a 99 year lease in order to maximise the privatisation proceeds. Similar reasoning may result in a structure in which different proportions of TransGrid and Endeavour Energy are privatised.

Assuming that this 51% ownership threshold is interpreted as a simple average across the four businesses (or across three businesses if any two businesses are merged), this could lead to various ownership permutations. The following table sets out three possible examples:

Click here to view table.

Other more creative solutions could be adopted, including the 100% privatisation of a merged distributor comprising both Ausgrid and Endeavour Energy. If the 51% level were interpreted as a weighted average across the regulated asset base of the businesses, other permutations would be possible (although weighting by the regulated asset base would reduce the extent of privatisation).

Transaction structure – treatment of a 99 year ‘partial lease’

The NSW Government has indicated that the privatisation of the electricity networks will occur by way of a 99 year ‘partial lease’. A similar 99 year lease structure was used for the recent port privatisations in NSW. A 200 year lease structure was used for the privatisation of the ETSA Utilities electricity distribution network in South Australia (SA).

If a combination of the approaches used in the NSW port privatisations and the ETSA privatisation were adopted, the following steps would occur:

  • First, the NSW Government would enact implementing legislation, potentially modelled in part on the Electricity Corporations (Restructuring and Disposal) Act 1999 of SA. This legislation would amend relevant NSW State legislation to facilitate and authorise the privatisation as well as effecting any changes necessary to implement the transaction and desired post-privatisation framework.
  • Second, the relevant assets to be privatised would be transferred into a State-owned Ministerial holding corporation (HoldCo), a State entity established by the implementing legislation to hold the network assets to be leased to the private sector. In SA, the HoldCo is known as the "Distribution Lessor Corporation".
  • Third, a Project Company would be created to enter into a 99 year lease with HoldCo. The lease would provide HoldCo the rights to operate/use the relevant network assets andto retain the economic benefits of any charges it imposes, but would also impose a range of performance and compliance obligations. Holdco would retain no control of the day to day operation of the network assets in its role as lessor under the 99 year lease.
  • Fourth, a separate 99 year lease may also be entered into with HoldCo by the Project Company for the lease of any associated land, but with HoldCo retaining freehold ownership. HoldCo would retain step-in rights and the ability to terminate both 99 year leases if the Project Company were to breach key obligations, but only following a predetermined 'cure period'.
  • Fifth, existing key contracts would be assigned to the Project Company. Some employees would also transfer to the Project Company, supported by various Government commitments intended to preserve employee entitlements.

The privatisation could subsequently occur by the sale of the shares in the Project Company to an investor in the desired proportion, such as 100% or 49%. In this manner, investors would be offered a pre-packaged deal without any involvement in the negotiation of the 99 year lease. Any such sale could involve a trade sale or an initial public offering (IPO).

In the SA privatisation of ETSA, bidders were given three different alternatives. Bidders could acquire shares in the Project Company, as identified above. Alternatively, bidders could receive a novation of the pre-packaged 200 year leases and acquire the assets and liabilities of the Project Company. Alternatively, bidders could negotiate their own 200 year leases (to replace the pre-packaged 200 year leases) and acquire the assets and liabilities of the Project Company. In SA, the successful bidder opted for the third of these three alternatives.

The situation becomes more complex if less than 100% of a business is privatised. An investor in a partial privatisation at less than 100% would, in practical effect, be entering into an incorporated joint venture with the NSW Government. In Australia, one precedent for such a structure is the TransACT joint venture.

In a joint venture structure, investors may seek a shareholder agreement (or constitutional provisions) that addresses key governance issues for the Project Company, including appointment of executives and voting rights on the Board of Directors. A private investor at less than 50% may wish to secure de facto control. However, an IPO of a partial interest is also possible as demonstrated by the 'T1' privatisation of Telstra.

The Government has announced that the NSW Future Fund will hold 100% of the shares in Essential Energy. Presumably that Fund would also hold any other partial State shareholdings in electricity businesses.

Sale price

As at June 2014, the sale price for the privatisation is not yet known. The sale price will depend heavily on the ultimate structure adopted for the privatisation.

However, the NSW Government has indicated that it intends to realise at least AUD 13 billion in aggregate from the lease of NSW’s electricity networks.

All of the sale proceeds are intended to be invested in new roads and other transport infrastructure projects in NSW. Assuming the Asset Recycling Fund Bill 2014 (Cth) is enacted, the NSW Government should also receive an amount of some AUD 2 billion as an incentive payment from the Commonwealth Government.

Conditions for the partial lease

In its ‘Rebuilding NSW’ policy for the 2015 State election, the Liberal/National Coalition has laid out strict conditions for the partial lease of the NSW electricity networks. These conditions are designed to promote the public interest and address community concerns.

The conditions already announced by the NSW Government include:

  • all net proceeds from the privatisation will be invested in new productive infrastructure, through the Restart NSW Fund;
  • electricity network prices will be discounted by 1% off forecast regulated prices until 2019;
  • the jobs of permanent award employees will be protected, and treated consistently with previous transactions;
  • the transaction will have no adverse impact on electricity reliability; and
  • the regional presence of the network businesses will be maintained.

It is possible that further conditions could be announced if the privatisation were to become a major political issue in the context of the 2015 NSW State election.

Preliminary issues

A number of issues raised by the proposed privatisation are briefly summarised below, including:

  • the extent to which any regulatory clearances may be required by bidders;
  • the manner in which network companies are subject to price regulation;
  • the impact of electricity demand on future cash flows; and
  • the manner in which requirements for future investment in network infrastructure will be addressed.

Regulatory clearances for bidders

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.

Click here to view table.

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:

Click here to view 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:

Click here to view table.

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:

Click here to view table.

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.

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.