Understanding your Electricity Bill

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Understanding your Electricity Bill

www.solsticeservices.com.au

Brisbane

PO Box 137, Greenslopes LPO, QLD 4120 P: +61 7 3367 1300

Melbourne

PO Box 118, Emerald VIC 3782 P: +61 3 5968 2117

Adelaide

PO Box 108, Dernancourt SA 5075 P: +61 407 945 547

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Disclaimer & limitations of this report

This analysis (the Guide) has been prepared by Solstice Development Services (SDS) Pty Ltd (Solstice) for the City of Playford for the purpose of assisting businesses to better understand the structure and content of their electricity bills to help them reduce costs (the Purpose).

The Guide was developed at the request of the City of Playford in conjunction with the development of the City of Playford Elizabeth South Manufacturing Precinct - Alternative Energy Study.

The Guide should not be solely relied upon for investment or other decisions. Solstice reserves the right to review and amend the Guide from time to time and to authorise in writing the use of the Guide for uses other than the Purpose by City of Playford. Solstice accepts no responsibility or liability for damages or loss suffered in anyway whatsoever resulting from any unauthorised use of the Guide.

The Guide has been prepared based upon information obtained from City of Playford, participating Elizabeth South manufacturing precinct businesses, energy suppliers and services providers, and from public sources that have not been audited by Solstice. Whilst statements in this Guide are given in good faith, Solstice accepts no responsibility for any errors in this information or the conclusions in this Guide.

The information in this Guide is commercially sensitive and subject to copyright and must not be used or reproduced either in full, part or summary without the prior written consent of Solstice.

Revision History

Date Author Provided to Summary of Update

9 Aug 2013 D Willis L Harris First draft – City of Playford version - provided for review.

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Over recent years, electricity invoices together with electricity procurement have become more complex.

The electricity industry has experienced utility disaggregation; separation of networks from power generation and electricity retail; privatisation; introduction of a national wholesale market; customers given the choice of multiple suppliers; the introduction of renewable energy schemes; and most recently the introduction of a carbon tax that is currently set to transition to an emissions trading scheme.

It has been difficult enough for electricity industry players to keep up, let alone electricity customers.

This guide is aimed at helping business customers better understand the current state of their electricity invoice. The layout of the bill may change from Retailer to Retailer, but the content is pretty consistent across all suppliers.

On the following pages, each section of the bill is dissected and explained.

# Invoice Item Value

1 ACCOUNT DETAILS

Account Number 9999 9999

Supply Address 99 street name, suburb, state, postcode Supply Period start 1 Mar 2013

Supply Period end 31 Mar 2013 Supply Period days 31 Invoice Issue date 2 Apr 2013 Payment due date 16 Apr 2013 METER DETAILS

2 Meter type Interval

3 NMI SAAAAAA000

4 Meter usage peak 20,000 5 Meter usage off peak 10,000 6 Total usage this period 30,000

7 DLF 1.0639

8 TLF 1.0029

9 Net Loss Factor 1.0670

# Invoice Item Units Quantity Units Rate (excl. energy losses) Rate (incl. energy losses) Charge (excl. GST) Charge (incl. GST) 10 ENERGY CHARGES 11 Peak kWh 20,000 $/kWh $0.08500 $0.09069 $1,813.88 $1,995.26 12 Off Peak kWh 10,000 $/kWh $0.03500 $0.03734 $373.44 $410.79 13 Carbon Adjustment kWh 30,000 $/kWh $0.02000 $0.02134 $640.19 $704.21

14 NETWORK CHARGES Energy based network charge

15 Network Peak 1 kWh 1,666.7 $/kWh $0.19380 $323.01 $355.31

Network Peak 2 kWh 6,666.7 $/kWh $0.19281 $1,285.41 $1,413.95

Network Peak 4 kWh 2,833.3 $/kWh $0.19281 $546.29 $600.92

16 Network Off Peak kWh 10,500.0 $/kWh $0.05497 $577.19 $634.90

17 Network Access Charge days 31 $/day $0.33547 $10.40 $11.44

18 RENEWABLE ENERGY CHARGES

19 REC - SRES - STC kWh 30,000 $/kWh $0.00768 $0.00817 $245.22 $269.74

20 REC - LRET - LGC kWh 30,000 $/kWh $0.00351 $0.00374 $112.17 $123.39

21 MARKET CHARGES

AEMO Pool Fees kWh 30,000 $/kWh $0.00040 $0.00042 $12.62 $13.88

AEMO Ancillary Charges kWh 30,000 $/kWh $0.00030 $0.00032 $9.58 $10.53

22 OTHER CHARGES

Retail Services days 31 $/day $1.23288 $38.22 $42.04

Meter Reading Fee meter days 31 $/meter/day $3.01370 $93.42 $102.77

Metering Charge meter days 31 $/meter/day $0.00000 $0.00 $0.00

TOTAL

23 Total kWh 30,000 $ $7,687.77 $8,456.55

24 Highest metered demand kVA 120.0 at: 14:00 on: Fri 1 Mar 2013

25 Carbon emissions tonnes 19.5

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Account Details

# Notes

The account details section identifies the customer’s Account Number and may also include a separate Invoice Number, and a record of the electricity supply address, which may be different to the billing address. It will record the supply (or billing) period start and end dates and the number of billing days in the period. Most large customers are on a monthly billing cycle, often coinciding with the calendar month start and finish dates. Smaller customers are often on a quarterly billing cycle of around 90 days. Historically payments have been due in arrears from around a few days to a couple of weeks after the invoice issue date.

Technical innovations in areas such as remote reading of meters, as opposed to the requirement for someone to visit and manually record consumption has allowed Retailers to offer other alternatives with respect to billing & payment cycles.

Increasingly, Retailers are offering a range of products to some customers including shorter billing cycles and “bill smoothing” products which allow customers to pay a regular and constant amount with a periodic “true up” once, or a number of times, per year to manage “unders and overs” (under estimation and over

estimation between actual meter reads).

This can help customers with greater budgeting and cash flow certainty and the reduction of administrative transaction costs through the use of automatic payment methods like direct debit.

It also helps Retailers with cash flow management by reducing the duration of the accounts receivable cycle that they face; which allows them to offer payment cycle related discounts including “pay on time” & “direct debit” discounts.

Which elements are negotiable and which elements are not?

Whilst there are a large number of elements that make up an electricity bill, in practice many of these items are of a "pass through" nature and the customer therefore can only check that they have been correctly applied and

calculated, rather than negotiate a lower rate.

As the bills have become more complex the propensity for errors has increased. Some anecdotal industry estimates put the proportion of business customer energy invoices in error as high as 20% to 30%.

The key areas where customers can typically influence their bills are: Peak and Off Peak energy rates, plus associated carbon charges (in order to accurately compare retail offers) and by ensuring the selection and maintenance of the correct network tariff.

Some other minor charges like environmental imposts may be negotiable, but are less material.

Account Number 9999 9999

Supply Address 99 street name, suburb, state, postcode Supply Period start 1 Mar 2013

Supply Period end 31 Mar 2013 Supply Period days 31 Invoice Issue date 2 Apr 2013 Payment due date 16 Apr 2013

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Meter Details

# Notes

METER DETAILS

2 Meter type

Some Retailers specify the meter type on the invoice. Meter type is identified typically as an “interval” meter which records energy consumption and other information on a “time of day” basis, eg. ½ hourly; or an “accumulation” meter which cumulatively records energy consumption and only records how much energy was consumed between read times. For accumulation meters, the invoice will often show “Previous read” quantity and “Current read” quantity.

The advent of “interval” meters has allowed the roll out of more sophisticated tariff products, including time-of-day pricing that provide incentives for customers to use more or less energy at different times of the day and days of the week.

3 NMI

The NMI or National Meter Identifier is a unique number for a customer’s metered connection point. A customer may have more than one metered connection point and therefore have more than one NMI. A NMI may also be associated with multiple meters at a single location.

A NMI is 10 characters long with an additional check digit eg: SAAAAAXXXX / X or 200XXXXXXX / X.

4 Meter usage peak

Peak usage is the quantity of electricity, measured in kilowatt hours (kWh), consumed during Peak times. Peak hours may vary slightly from Retailer to Retailer, but typically in SA it refers to electricity consumed on business days between the hours of 07:00 and 21:00 (Central Standard Time). Meters and meter readings are not adjusted for daylight savings changes.

For customers with metering that does not recognise specific days, Peak energy is energy consumed on each day between the hours of 07:00 and 21:00 (Central Standard Time).

For each NMI there may be separate accumulation "sub-meters" for Peak & Off-Peak consumption, or a single interval meter from which Peak times can be distinguished from Off-Peak times.

5 Meter usage off peak

Off Peak usage refers to the quantity of energy consumed at times other than Peak times.

The concept of a “Shoulder” time period between Peak and Off-Peak times is really only used in NSW and the ACT regions of the NEM, and does not typically apply in SA.

METER DETAILS

2 Meter type Interval

3 NMI SAAAAAA000

4 Meter usage peak 20,000 5 Meter usage off peak 10,000 6 Total usage this period 30,000

7 DLF 1.0639

8 TLF 1.0029

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# Notes

6 Total usage this period

Total usage is the sum of Peak usage and Off Peak usage. Based on the definition of Peak hours above, 40% of hours in the year are Peak hours and 60% are Off Peak.

In SA over the past 5 years, 46% of electricity demand occurred at Peak times and 54% at Off Peak times.

Electrical losses and loss factors

Electricity is “lost” during transport as it flows from power stations to consumers’ meters due to electrical

resistance and the heating of conductors. On average across the National Electricity Market (NEM) these losses are the equivalent of approximately 10% of the total electricity generated by power stations.

Retailers buy electricity from the wholesale market and incur these losses in the transport of electricity to the customer meter. The application of loss factors to the customer bill serves to compensate the Retailer for the cost that they face associated with these losses as they have to pay the cost of the energy generated for their customers including the losses from the common market reference point to the customer site.

The loss factors are used to either “scale up” the unit price of electricity and associated products or to “scale up” the quantity of electricity. The effect of either method is the same.

On some invoices customers will see a unit price for electricity or “rate” exclusive of electrical losses and another “rate” inclusive of electrical losses, which has been scaled up by the relevant loss factor.

Other customers will see an alternative approach for achieving the same result which uses a constant price rate but increases the quantity. In this case a quantity, for example, of Peak energy that is the metered quantity is added to another quantity to account for the losses related to that item without a price change.

The following diagram provides a simple illustration of the transport of electricity.

Source: AEMO

Losses across the high voltage Transmission system are accounted for using the TLF (transmission loss factor) [sometimes referred to as the “MLF” or “Marginal Loss Factor”], and losses across the Distribution system are accounted for using the DLF (distribution loss factor).

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# Notes

7 DLF or Distribution Loss Factor

DLFs are recalculated annually by AEMO (Australian Energy Market Operator) and apply for a financial year commencing on 1 July. Different customer network tariff classes are allocated different connection point DLF codes. Some very large customers connect directly to the transmission system and consequently do not have a DLF. The rates that apply for FY2014, commencing 1 July 2013 and the comparison rates that applied in SA for FY2013 are as follows:

Class Tariff Code FY2013 DLF FY2014 DLF

Low Voltage Unmetered NLV2 1.0800 1.0770

Low Voltage Residential NLV2 1.0800 1.0770

Low Voltage Controlled Load (hot water) NLV2 1.0800 1.0770

Low Voltage Business Single Rate NLV2 1.0800 1.0770

Low Voltage Business Two Rate NLV2 1.0800 1.0770

Low Voltage Transformer LV Demand NLV1 1.0639 1.0615

High Voltage HV Demand Two Rate NHV1 1.0381 1.0367

Substation Substation NZS1 1.0177 1.0170

Low Voltage refers to supply at a voltage of 230 volts single phase or 400 volts three phase. High Voltage refers to supplies at voltages of 11,000 volts (11 kV) or 22,000 volts (22kV).

Substation class refers to supplies at sub-transmission level of 33,000 volts (33kV) or 66,000 volts (66kV).

8 TLF or Transmission Loss Factor (also known as “MLF” or “Marginal Loss Factor”)

TLFs are also recalculated annually by AEMO and apply for a financial year commencing on 1 July. A TLF factor is associated with a Transmission Node Identities (TNI) Code which is related to a specific transmission connection point or a virtual transmission node. Customer connections with an annual energy consumption exceeding 160 MWh are typically assigned to a transmission connection point, taking into account the normal network connections and predominant energy flows across that network. Smaller customer connections with an energy consumption of 160MWh annually or less are assigned to the virtual transmission node (VTN).

The relevant rates with respect to the Elizabeth South precinct that apply for FY2014, commencing 1 July 2013 and the comparison rates that applied for FY2013 are as follows:

Location Voltage TNI Code FY2013 TLF FY2014 TLF

SA virtual transmission node (VTN) SJP1 0.9981 1.0005

PARA substation 66 kV SPAR 1.0029 1.0036

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# Notes

9 Net Loss Factor

The Net Loss Factor is calculated as the product of the DLF and TLF.

In the case on this example invoice the Net Loss Factor is 1.0670 (1.0639 * 1.0029 = 1.0670) representing net losses of 6.7% which are passed through to the customer.

Energy Charges

# Notes

10 ENERGY CHARGES

The energy charges are the key negotiable element of the electricity supply to be agreed with the Retailer. Wholesale energy prices are set in a competitive spot market each half hour and the Retailer pays the Australian Energy Market Operator (AEMO) to purchase electricity each half hour for supply to customers. Because the National Electricity Market (NEM) spot market price can be highly volatile, Retailers also enter into price hedging contracts with electricity generators (and other market traders) to manage the risk associated with the price at which they buy wholesale electricity. Many Retailers also have their own power generation facilities which acts as a natural hedge on their electricity purchases from the NEM (ie. they “sell” energy to themselves via their own generation).

Consumption load shape or the amount of electricity consumed on week days versus weekends and during the day versus overnight varies from customer to customer. Consequently, the effective cost of purchasing that electricity from the wholesale market varies in terms of cost of sales to a Retailer for each customer. The unpredictability of some customer loads also makes them more costly for the Retailer to manage because the uncertainty affects the levels of hedging that they must undertake in advance via the financial markets. To understand the potential load fluctuation and variation of customers, Retailers will often ask for historic metering data or permission to access this historic half-hourly data. It is usually in the customer’s interest to provide access to this data to the Retailer, because if they don’t have it then they may assume worse case load fluctuation and shape than actually exists which will increase the energy charge prices to the customer. To further mitigate the costs associated with load variations, Retailers may invoke an additional charge or a right to re-price energy outside of permitted variations above or below an annual forecast, ie. variations within +/- x% only are allowed. This Retailer contract clause too is usually negotiable.

On average, the energy charges (excluding carbon adjustment) typically make up around 30% to 40% of the total electricity bill for business customers.

The following chart shows actual SA Peak and Off Peak average wholesale electricity prices monthly for FY2013.

# Invoice Item Units Quantity Units Rate (excl. energy losses) Rate (incl. energy losses) Charge (excl. GST) Charge (incl. GST) 10 ENERGY CHARGES 11 Peak kWh 20,000 $/kWh $0.08500 $0.09069 $1,813.88 $1,995.26 12 Off Peak kWh 10,000 $/kWh $0.03500 $0.03734 $373.44 $410.79 13 Carbon Adjustment kWh 30,000 $/kWh $0.02000 $0.02134 $640.19 $704.21

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Source: Solstice

# Notes

11 Peak

As the above chart shows, spot market Peak prices in SA exceeded Off Peak prices for each month during FY2013.

The first Peak price appearing on the electricity invoice is referenced to the “Regional Reference Node” which is a value before losses have been applied (nominally the “Regional Reference Node” refers to a common wholesale market reference point in the SA region located in the 66kV switch yard at the Torrens Island Power Stations). To convert this common market location Peak price to the customer’s meter, the net loss factor is applied to the price to scale up the Peak price from the reference node to the meter. In the case of this invoice example, the Peak price is “scaled up” by 6.7% (refer above to 9. Net Loss Factor).

An alternative method, which produces the same result, serves to scale up the quantity. Some Retailer invoices show the metered Peak electricity consumption quantity and an additional quantity to account for losses (in kWh) from the Regional Reference Node to the meter.

The above chart shows a full year of monthly Peak and Off Peak wholesale electricity spot prices in SA. The following chart looks back by month over 5 years to show that while both Peak and Off Peak prices did rise overall coincident with the implementation of the carbon tax from July 2012, there are other market effects that can see very high price spikes in the electricity market (eg. caused by extreme weather events or significant power station breakdowns and outages). It is this type of volatility that can have a large impact on average monthly wholesale spot prices and ultimately impact what prices Retailers decide to charge

Customers. 0 20 40 60 80 100 120 140 160 180 200 $ /M Wh

SA spot market wholesale prices FY2013

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Source: Solstice

# Notes

12 Off Peak

Off Peak energy pricing rates are pretty much always at or below Peak pricing rates.

The calculation treatment of Off Peak prices to account for losses is the same as described above for Peak pricing.

13 Carbon Adjustment

Some Retailers offer the choice of including the carbon price in the Peak and Off Peak energy prices as an alternative to identifying the carbon charge explicitly on the invoice.

The charge associated with the carbon tax is referred to as a “carbon adjustment” on most Retailer invoices. The carbon tax commenced from 1 July 2012 and is applied to large emitters of carbon dioxide, including fossil (eg. coal, gas) fuelled power stations. The application of the carbon tax is designed to provide a financial incentive to electricity producers to reduce carbon emissions by using less carbon intensive technologies to generate electricity and to substitute going forward with “cleaner” technologies.

The resulting increased costs associated with electricity production through the inclusion of the tax and/or the use of more expensive, but less carbon intensive, technologies flows through into the wholesale electricity market.

The key factors that contribute to the carbon adjustment for the customer include the:

 actual carbon tax (price) rate, which was fixed at $23 per tonne for FY2013, increasing to $24.15 for FY2014, and thereafter will have either one more year at a fixed price, or will be allowed to “float” with the price set by the market;

0 50 100 150 200 250 300 350 400 450 500 550 $ /M Wh

SA spot market wholesale prices FY2008 to FY2013

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NOTE: The Federal Opposition has announced that they will remove the carbon tax if elected to Government at the 2013 election. The proposed timing and transaction arrangements are not known at the time of producing this guide.

 the carbon intensity (quantity) rate, which is the amount of carbon emitted per unit of electricity production. This carbon intensity rate varies by power station (eg. the carbon intensity rate of a coal fired power station is greater than gas fired, etc.) and on average from state to state (eg. Victoria is high because the generation fleet is dominated by high CO2 producing brown coal fuelled generation,

and Tasmania is low as it is dominated by zero emission hydro power generation); and

 the net loss factor, to scale up the carbon adjustment rate from the regional reference node to the meter.

Carbon emissions rates to be applied by Retailers on customer bills are not regulated which makes the “carbon adjustment” a potentially negotiable element of the electricity bill.

In the short-term, while the carbon tax “price” is fixed, negotiation will only be around the rate of emissions intensity. If the carbon tax remains and the carbon tax regime transitions to an emissions trading scheme (ETS), which is the current policy of the current government, the “price” will float and be set by market mechanisms which will mean both the price and rate of intensity will effectively be negotiable.

The variation in actual emissions intensity varies significantly from State to State. The following table shows the average for each NEM state and the NEM as a whole for FY2013 in tonnes of carbon dioxide equivalent emissions per megawatt hour of electricity production (tCO2-e/MWh):

Period NEM NSW QLD SA TAS VIC

FY2013 0.8750 0.9038 0.8382 0.5169 0.0581 1.1773

To put this value in perspective using the FY2013 fixed price of $23 per tonne, and comparing the NEM average intensity with the SA average intensity, and using the same net loss factor of 1.0670:

NEM intensity = $23 * 0.8750 * 1.0670 = $21.47 per MWh or 2.147 cents per kWh. SA intensity = $23 * 0.5169 * 1.0670 = $12.68 per MWh or 1.268 cents per kWh.

That is to say that the SA average emissions intensity was at a 41% discount to the NEM average emissions intensity over FY2013.

From a sample of business customer invoices in the City of Playford reviewed during FY2013 it appears that Retailers are using a range of intensity rates around the NEM average rather than the SA average.

For a business customer consuming 300MWh per year in FY2013: NEM intensity: $6,441 carbon adjustment SA intensity: $3,804 carbon adjustment Difference: -$2,637

The Retail contract with the customer should specify the carbon rate and intensity or method to be applied on the invoice. As the simple illustration above highlights, it is potentially an important part of contract negotiations.

Retailers may differ with respect to their individual policies on how they will recover the costs they face with respect to the carbon imposts. Some may choose to smear the same emissions rate across their national customer base and others may choose to differentiate by State. The key point to note is that when

comparing quotes and offers from Retailers during periodic energy procurement cycles, the treatment of this new carbon impost could alter the customer’s selection of preferred Retailer.

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Network Charges

# Notes

14 NETWORK CHARGES

Network tariffs are regulated by the Australian Energy Market Commission (AEMC) and prices are published annually for each financial year commencing from 1 July.

There are two network service providers (NSPs) in South Australia:

 ElectraNet, a transmission network service provider (TNSP), which owns and manages the high-voltage electricity transmission network; and

 SA Power Networks (SAPN) (formerly known as ETSA Utilities), a distribution network service provider (DNSP), which owns and manages the low-voltage electricity distribution network. The Retailer collects network charges from the customer on behalf of the NSPs and passes that regulated revenue through to the NSPs. The network charges cover the regulated costs of the NSPs for building, managing and maintaining the transmission and distribution wires network assets including some customer metering.

Various network tariffs are set for different types of customers. In some cases there may be more than one network tariff that is potentially applicable to a customer. It is in the customer’s interest to be on the lowest cost network tariff and this should be reviewed periodically to confirm that the customer remains on the optimal tariff for their circumstances.

Some network tariffs are largely “energy based” which tends to make them a low fixed cost, but relatively high variable cost tariff. Other network tariffs are largely “demand or capacity based” which tends to make them a high fixed cost, but relatively low variable cost.

Irrespective of the network tariff type, no losses (DLFs or TLFs) are applied to network charges.

The case studies show more specific details, but the following chart illustrates the situation for a business customer consuming approximately 375,000kWh per year, with a maximum demand of 120 kVA.

The comparison made is between the “Business 2 rate” tariff (low fixed, high variable), and the “Low Voltage Stepped Demand” tariff (high fixed, low variable).

Assuming a power factor of unity with 66% of energy consumed at Peak times, the example customer is approximately $16,000 per year (30%) better off on the Low Voltage Stepped Demand tariff than the Business 2 rate tariff.

If the customer’s annual consumption was below approximately 225,000 kWh however, the customer would be better off on the Business 2 rate tariff.

# Invoice Item Units Quantity Units Rate (excl. energy losses) Rate (incl. energy losses) Charge (excl. GST) Charge (incl. GST)

14 NETWORK CHARGES Energy based network charge

15 Network Peak 1 kWh 1,666.7 $/kWh $0.19380 $323.01 $355.31

Network Peak 4 kWh 2,833.3 $/kWh $0.19281 $546.29 $600.92

16 Network Off Peak kWh 10,500.0 $/kWh $0.05497 $577.19 $634.90

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Source: Solstice

# Notes

15 Network Peak (energy based network tariff)

Network Peak energy refers to energy consumed on business days between the hours of 07:00 and 21:00 (Central Standard Time). This is also typically the definition of Retail Peak energy in SA, but some Retailers may have a slightly different definition, e.g. if adopting the NEM definition of Peak period which refers to energy consumed on business days between the hours of 07:00 and 22:00 (Eastern Standard Time). For Distribution Network Users with metering that does not recognise specific days, Peak energy is energy consumed on each day between the hours of 07:00 and 21:00 (Central Standard Time).

Due to this potential for different definitions of Peak time periods between the NSP and Retailer, there are sometimes slight differences on the invoice with regard to the quantity of Peak energy for the invoice period between the energy charges and network charges.

There are numerous types of network tariffs that may apply.

The example shown on this illustrative invoice is an “energy based” network tariff that is largely a variable charge based on the level of consumption (kWh).

This Monthly Low Voltage Business Two Rate tariff has 4 Peak charging blocks, with a separate price for each incremental block, as follows:

 Peak Block 1 Usage Rate: First 1,666.7 kWh per month (effective proxy for 20,000 kWh per year);

 Peak Block 2 Usage Rate: Next 6,666.7 kWh/month (next 80,000 kWh p.a.);

 Peak Block 3 Usage Rate: Next 8,333.3 kWh/month (next 100,000 kWh p.a.); and

 Peak Block 4 Usage Rate: Balance of usage beyond 16,666.7 kWh/month (beyond 200,000 kWh p.a.).

$-$5,000 $10,000 $15,000 $20,000 $25,000 $30,000 $35,000 $40,000 $45,000 $50,000 $55,000 $60,000 N e tw o rk Co st s kWh Network Options-375-PF1

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However, whilst 4 different pricing blocks are published, only 2 different prices apply. They are for the first 1,666.7 kWh per month which is charged at 19.38 cents per kWh (FY2013 excluding GST), and then any volume above 1,666.7 kWh per month is charged at 19.281 cents per kWh.

Note that these network charges are only to cover payment for the use of the transmission and distribution “wires” for the month and these charges are passed straight through from the Retailer to the NSPs.

These charges are regulated and not negotiable (however, the customer may find that they can take advantage of a more attractive network tariff – see the Case Studies following for more detail).

16 Network Off Peak (energy based network tariff)

Network Off Peak energy refers to energy consumed at times other than Peak times.

The Monthly Low Voltage Business Two Rate tariff has only 1 Off Peak charging block and all Off Peak energy quantity has a network charge, in this example, of 5.497 cents per kWh (FY2013 excluding GST).

Note that these network charges are only to cover payment for the use of the transmission and distribution “wires” for the month and these charges are passed straight through from the Retailer to the NSPs.

These charges are regulated and not negotiable.

17 Network Access Charge (energy based network tariff)

In addition to the energy based Peak and Off Peak variable network charges under the Monthly Low Voltage Business Two Rate tariff, there is also a day based charge of 33.547 cents per day (FY2013 excluding GST). This Supply Rate may also be referred to as a Network Access Charge on some Retailer invoices.

The Network Access Charge is also regulated and not negotiable.

Capacity based (stepped demand) network charges

The alternative primary pricing structure for network charges within the range of network tariffs is largely “capacity based” as opposed to the previously described “energy based” tariff structure.

The following example describes the key elements of one of these capacity based network charging structures using the Low Voltage Stepped Demand (minimum 80 kVA) (VLVS) tariff.

# Invoice Item Units Quantity Units Rate (excl. energy losses) Rate (incl. energy losses) Charge (excl. GST) Charge (incl. GST) 14 NETWORK CHARGES Capacity based network charge

15a Network Peak kWh 20,000 $/kWh $0.03723 $744.60 $819.06

16a Network Off Peak kWh 10,000 $/kWh $0.03723 $372.30 $409.53

17a1 Demand Step 1 kVA 100.0 $/kVA/mth $17.90703 $1,790.70 $1,969.77

17a2 Demand Step 2 kVA 20.0 $/kVA/mth $12.02490 $240.50 $264.55

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# Notes

15a Network Peak (capacity based network tariff)

The Network Peak energy charge is applied as a rate per kWh of energy consumed during Peak times on the VLVS tariff in the same way as similar rates are applied in the above energy based (Monthly Business 2 rate) network charge example. However, under the VLVS tariff there is only a single rate of 3.723 cents per kWh (FY2013 excluding GST) that applies for all Peak energy (as opposed to the 4 block tariff regime that applies to the Monthly Business 2 rate network tariff). This variable rate is much lower on the VLVS tariff which is dominated by the capacity or stepped demand charges.

16a Network Off Peak (capacity based network tariff)

There is also only a single Network Off Peak energy charge applied as a rate per kWh under the VLVS tariff. The Off Peak energy charge in this case is the same as the Network Peak energy charge of 3.723 cents per kWh (FY2013 excluding GST).

17a1 Network Demand Step 1 Charge (capacity based network tariff)

In addition to the energy based Peak and Off Peak variable network charges under the VLVS tariff, there is also a series of capacity or stepped demand based charges.

These demand charges are determined on the basis of:

 agreed maximum “Annual Demand” (which occurs within an SAPN specified period); and

 agreed maximum “Additional Demand” (which occurs at any other time in the year).

Agreed Annual Demand is the highest demand expected to be required in the period 12:00 to 20:00 on working days in December through March (Central Standard Summer Time). This may be determined by agreement or by historically recorded demand. This time of day on work days through Summer and March is when the coincident customer Peak demands on the network are at their highest.

Agreed Additional Demand is the amount, if any, that the Agreed Anytime Demand exceeds the Agreed Annual Demand.

Agreed Anytime Demand is the highest demand expected to be required outside of the times that the Agreed Annual Demand applies. This may be determined by agreement or by historically recorded demand. This may be equal to or higher than the Agreed Annual Demand but not less.

This overall structure gives customers a price incentive to avoid achieving their annual maximum demand during the period from noon till 8pm (Central daylight saving time) on working weekdays over the months of Summer and March each year.

The Low Voltage Stepped Demand (VLVS) tariff has 5 demand step charging blocks, with a separate price for each incremental block.

The Demand Step 1 charge is $17.90703 per kVA per month (FY2013 ex GST) for the first 100 kVA and with a minimum of 80 kVA applied.

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# Notes

The Demand Step 2 charge is $12.0249 per kVA per month (FY2013 ex GST) for the next 150 kVA.

The Demand Step 3 charge is $9.81889 per kVA per month (FY2013 ex GST) for the next 750 kVA.

The Demand Step 4 charge is $8.347020 per kVA per month (FY2013 ex GST) for the kVA balance beyond 1,000 kVA.

17a5 Network Additional Demand Charge (capacity based network tariff)

The Demand Step 5 charge for Additional Demand is $4.55851 per kVA per month (FY2013 ex GST) to the extent, if any, that the Agreed Anytime Demand exceeds the Agreed Annual Demand in kVA.

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Renewable Energy Charges

# Notes

18 RENEWABLE ENERGY CHARGES

The Mandatory Renewable Energy Target (MRET) scheme was introduced by the Federal Government to encourage investment in low emissions renewable energy power generation, and commenced in 2001. This scheme evolved into two parts from January 2011 which operate as:

 Large-scale Renewable Energy Target (LRET); and

 Small-scale Renewable Energy Scheme (SRES). Both schemes are currently planned to run until 2030.

LRET is designed to encourage the deployment of large-scale renewable energy projects such as wind farms. SRES is designed to support the installation of small-scale systems, including solar photo-voltaic (PV) panels and solar water heaters.

LRET & SRES require electricity Retailers to purchase a mandated quantity of renewable energy certificates each compliance year (calendar year) and surrender those certificates to the Clean Energy Regulator. Certificates related to the LRET are called LGCs (Large scale Generation Certificates).

Certificates related to the SRES are called STCs (Small scale Technology Certificates).

The LRET and SRES are Federal Government initiatives. There are also a number of other State Government based renewable energy schemes, but none currently operate in South Australia that appear as a separate charge on customer invoices.

The renewable energy charges on the customer bill are how the Retailer recovers the cost of its mandatory LGC & STC surrender obligations.

19 REC – SRES – STC

Retailers, as “liable entities” are required to purchase and surrender STCs based on the size of their electricity loads (ie. the loads of their customers). The quantity of STCs that Retailers must surrender each year is determined by the Small-scale Technology Percentage (STP) which is set annually (calendar year) by the Clean Energy Regulator according to the Regulations.

The Retailer must pay a penalty for any shortfall in the surrender of their STCs to the Regulator. The Small-scale Technology Shortfall Charge (STSC) is currently $65 per STC. However, as the shortfall charge is not deductible for income tax purposes, the effective penalty is closer to $93 per STC which is the shortfall charge divided by the reciprocal of the Company Income Tax Rate (ie. $65/(1-30%) = $92.86). In practice Retailers purchase most if not all of their requirements to avoid shortfall penalties.

The STP for calendar year 2013 (CY2013) is 19.7%, meaning that a Retailer must purchase and surrender 197 STCs for every 1,000 MWh of electricity that it purchases from the wholesale market on behalf of its

customers.

# Invoice Item Units Quantity Units Rate (excl. energy losses) Rate (incl. energy losses) Charge (excl. GST) Charge (incl. GST) 18 RENEWABLE ENERGY CHARGES

19 REC - SRES - STC kWh 30,000 $/kWh $0.00768 $0.00817 $245.22 $269.74

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STCs are a tradeable commodity attached to eligible installations of SRES systems with a maximum threshold size of 100kW (eg. for solar PV).

The Australian Government has capped the price of STCs at $40 per MWh (4 cents per kWh) but the actual value of an STC varies from day to day. STCs are traded on the STC market meaning the price will vary

according to supply and demand. As at the end of July 2013, CY2013 STCs traded at ~$39 per MWh (3.9 cents per kWh).

Based on July 2013 STC market prices, the indicative cost to the Retailer for CY2013 is approximately: $39 * 19.7% = $7.683 per MWh or 0.7683 cents per kWh.

However, the Retailer incurs theoretical losses when recovering the cost of STCs from customers. The losses associated with STCs do not include transmission losses, but only distribution losses, ie. The DLF is included and the TLF is excluded.

Consequently, using the cost base of $39 per STC and the DLF in the example invoice of 1.0639, the indicative (no margin) pass through price from the Retailer to the customer for CY2013 is approximately:

$39 * 19.7% * 1.0639 = $8.174 per MWh or 0.8174 cents per kWh.

Recent STC prices have ranged from mid to high $20s in early FY2013 to just below the $40 cap price at the end of FY2013:

Source: EUAA

These charges will vary from Retailer to Retailer and over time and while relatively minor, may be negotiable.

20 REC – LRET – LGC

Retailers, as “liable entities” are required to purchase and surrender LGCs based on the size of their electricity loads (ie. the loads of their customers). The quantity of LGCs that Retailers must surrender each year is determined by the Renewable Power Percentage (RPP) which is set annually (calendar year) by the Clean Energy Regulator according to the Regulations.

The Retailer must pay a penalty for any shortfall in the surrender of their LGCs to the Regulator. The Large-scale Generation Shortfall Charge (LGSC) is currently $65 per LGC. However, as the shortfall charge is not deductible for income tax purposes, the effective penalty is closer to $93 per LGC which is the shortfall charge divided by the reciprocal of the Company Income Tax Rate (ie. $65/(1-30%) = $92.86). In practice Retailers purchase most if not all of their requirements to avoid shortfall penalties. Plus some Retailers invest

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in renewable projects such as wind and solar directly to generate LGCs.

The RPP for calendar year 2013 (CY2013) is 10.65%, meaning that a Retailer must purchase and surrender 106.5 LGCs for every 1,000 MWh of electricity that it purchases from the wholesale market on behalf of its customers.

LGCs are a tradeable commodity created by accredited RET power stations at a rate of 1 LGC for every MWh of eligible renewable electricity generated above the power station's baseline.

There is no explicit price cap for LGCs, however, the Large-scale Generation Shortfall Charge (LGSC) described above sets an effective cap price.

LGCs are traded in the open market, where the price will vary according to supply and demand and the actual value of an LGC varies from day to day. As at the end of July 2013, CY2013 LGCs traded at ~$33 per MWh (3.3 cents per kWh).

Based on July 2013 LGC market prices, the indicative cost to the Retailer for CY2013 is approximately: $33 * 10.65% = $3.515 per MWh or 0.3515 cents per kWh.

However, the Retailer incurs theoretical losses when recovering the cost of LGCs from customers. The losses associated with LGCs do not include transmission losses, but only distribution losses, ie. The DLF is included and the TLF is excluded.

Consequently, using the cost base of $33 per LGC and the DLF in the example invoice of 1.0639, the indicative (no margin) pass through price from the Retailer to the customer for CY2013 is approximately:

$33 * 10.65% * 1.0639 = $3.739 per MWh or 0.3739 cents per kWh.

Recent CY2013 LGC prices have ranged from low $40s in early FY2013 to low $30s at the end of FY2013:

Source: EUAA

Forward LGC prices for CY2014 have tracked at about $1 to $2 above CY2013 over the past year, and forward LGC prices CY2015 have tracked at about $2 to $4 above CY2013 over the same period.

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Market Charges

# Notes

21 MARKET CHARGES

Retailers, as participants in the NEM, are obliged to pay fees to AEMO to cover:

 A share of the annual operating costs of AEMO as the market operator; and

 Ancillary services which are other costs associated with operating and maintaining a stable and reliable interconnected electricity system.

AEMO Pool Fees

AEMO Pool Fees (or Market Fees) are allocated to Retailers by AEMO on a rate per MWh basis based on the size of their electricity loads (ie. the loads of their customers). The AEMO budget is re-set annually on a financial year basis commencing from 1 July each year. The Retailer rate for FY2013 was $0.3954 per MWh excluding GST (0.0004 cents per kWh).

To fully cover the cost of AEMO Pool Fees the Retailer needs to scale up by the Net Loss Factor (TLF & DLF) in the pass through to the customer, which increases the charge using the same net loss factor of 1.0670 to:

AEMO Pool Fees = $0.3954 * 1.0670 = $0.4219 per MWh or 0.00042 cents per kWh.

AEMO Ancillary Charges

Ancillary services are those services used by AEMO to manage the power system safely, securely and reliably. These services maintain key technical characteristics of the system, including standards for frequency, voltage, network loading and system restart processes.

AEMO operates eight (8) separate markets for the delivery of frequency control ancillary services (FCAS) and purchases network control ancillary services (NCAS) and system restart ancillary services (SRAS) under agreements with service providers.

The actual ancillary services costs to AEMO can vary significantly from week to week.

AEMO recovers some ancillary services costs (around 40% to 50%) on a “causer pays” basis which is largely met by the generation power stations. The balance of ancillary services is recovered primarily from the Retailers.

The Retailers’ share of AEMO Ancillary Charges over FY2013 were approximately $0.30 per MWh excluding GST (0.0003 cents per kWh).

To fully cover the cost of AEMO Ancillary Charges the Retailer needs to scale up by the Net Loss Factor (TLF & DLF) in the pass through to the customer, which increases the charge using the same net loss factor of 1.0670 to:

AEMO Ancillary Charges = $0.30 * 1.0670 = $0.3192 per MWh or 0.00032 cents per kWh. Both of these charges are typically treated as a pass through and if passed through at cost are essentially not for negotiation.

# Invoice Item Units Quantity Units Rate (excl. energy losses) Rate (incl. energy losses) Charge (excl. GST) Charge (incl. GST) 21 MARKET CHARGES

AEMO Pool Fees kWh 30,000 $/kWh $0.00040 $0.00042 $12.62 $13.88

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Other Charges

# Notes

22 OTHER CHARGES

There are a number of other charges that may appear on the customer invoice.

These other charges are typically charged on a per day, per month, per meter or per NMI basis rather than an energy or capacity basis. As a consequence of their charging basis, these other charges are not typically scaled up for losses.

Retail Services

Retail services may cover value added services provided by the Retailer or another third party, including for example such items as:

 Bill reconciliation services;

 Energy consumption reporting; and

 Emissions reporting.

Retail services fees (or “Administration charges”) may be negotiable and vary on a case by case basis depending on the type and extent of value added services provided.

Meter Reading Fee & Metering Charge

The meter reading fee refers to the cost of services typically provided by the meter data provider which may be limited to meter data: acquisition, monitoring, warehousing and transfer; or include other value added reporting services.

The metering charge fee relates to payment for the use of the physical meter, including the supply, installation, testing and audit of the meters. Depending on the network tariff type and selected metering provider, the metering charge may be an explicit charge or it may be included in the network charges section of the invoice.

It is not unusual to see a single consolidated “Metering Services” item on the invoice which covers both meter reading (meter data provider) fees and metering charges.

The meter reading fee & metering charge may represent a combination of negotiable charges and/or pass through charges from the Retailer.

# Invoice Item Units Quantity Units Rate (excl. energy losses) Rate (incl. energy losses) Charge (excl. GST) Charge (incl. GST) 22 OTHER CHARGES

Retail Services days 31 $/day $1.23288 $38.22 $42.04

Meter Reading Fee meter days 31 $/meter/day $3.01370 $93.42 $102.77

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Total

# Notes

TOTAL

23 Total

The total item on the invoice will sum up the total electricity consumption for the invoice period, plus the total amount payable, typically with and without GST.

24 Highest metered demand

For customers with interval metering, and particularly those on capacity based network tariffs, the highest metered demand (maximum demand) for the invoice period together with the date and time that it occurred will be reported.

The Power Factor may also be reported together with maximum demand. Power Factor is essentially a type of efficiency measure. The power factor of a load is given by the ratio of kW (active power) divided by kVA (apparent power) at any given moment. The value of a power factor will range from 0 to 1.

A power factor close to unity means that the reactive energy is small compared with the active energy, while a low value of power factor indicates the opposite condition. The closer the power factor approaches its maximum possible value of 1, the greater the benefit to the customer and the supplier. Network service providers may require customers to install power factor correction equipment if the power factor is

consistently outside of the required standard, and for some network tariffs the power factor may impact the network charge.

25 Carbon emissions

Carbon emissions are typically reported on the invoice as “estimated greenhouse gas emissions for this bill” in tonnes of carbon dioxide equivalent for the period.

However, the emissions intensity rate (discussed in detail at “13. Carbon Adjustment” above) may not be made explicit. This rate can be simply calculated by dividing the reported tonnes of carbon dioxide by the electricity consumption (in MWh, ie. kWh divided by 1,000) for the invoice period.

This calculated emissions intensity rate may not reconcile with the emissions intensity rate that the customer is being charged via the carbon adjustment for a number of possible reasons including:

 The estimated reporting rate being used is different to the carbon adjustment charge rate;

 The total electricity consumption has not been adjusted for losses, but the carbon emission rate has or vice versa.

The carbon emissions are often reported in a chart together with monthly electricity consumption. # Invoice Item Units Quantity Units Rate (excl.

energy losses) Rate (incl. energy losses) Charge (excl. GST) Charge (incl. GST) TOTAL 23 Total kWh 30,000 $ $7,687.77 $8,456.55

24 Highest metered demand kVA 120.0 at: 14:00 on: Fri 1 Mar 2013

25 Carbon emissions tonnes 19.5

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Case Studies

The foregoing guide has dissected and explained each section of the typical electricity bill in detail for a theoretical business customer in South Australia.

Actual electricity invoices were gathered from a sample of 11 companies in the Elizabeth South precinct of the City of Playford in the first half of 2013 as part of the Elizabeth South Manufacturing Precinct, CleverGreen

Eco-Innovation Program, Alternative Energy Study.

While anonymity with respect to this confidential pricing data is being maintained for the wider sample group, two businesses agreed to disclose their electricity pricing information and experience for the purposes of these case studies.

The following chart summarises the average total cost of delivered electricity (including carbon adjustments and network charges, and excluding GST) taken from individual bills issued in late 2012 and early 2013. The chart shows that average costs varied widely across the Elizabeth South precinct from a low of approximately $0.17/kWh (17 cents per kilowatt hour) to a high which is double that rate at $0.34/kWh.

Source: Solstice

It is clear from the above chart that the dominant 3 elements of the electricity bill are the network charges,

electricity price (excluding carbon), and the carbon charge. Of these elements, the electricity price (Peak rate and Off Peak rate) is negotiable, the network charge is a regulated pass through, and the carbon price has only been in existence since July 2012.

The cost stacks represented in this chart for Levett Engineering Pty Ltd and Sonnex Engineering Pty Ltd, who are the case study subjects, both represent the “before” case.

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 Levett Engineering Sonnex Engineering ce n ts p e r kWh

City of Playford - Elizabeth South Precinct - Participant Companies

Grid Supply Total Charges (2013)

Other Metering Retail Service

Carbon (environmental) STC (environmental) LGC (environmental)

Network Ancillary Services (market) AEMO Fees (market)

Electricity price (excl Carbon)

25.7 c/kWh

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During the process of the review of the sample of electricity contracts and invoices that were supplied, evidence was discovered of:

 Discrepancies between agreed contracted rates and invoiced rates for some customers;

 Discrepancies between published regulated network charges and the invoiced rates for those pass-through charges;

 Some customers on un-competitive (relatively high) electricity rates; and

 Some customers on sub-optimal (very high) network tariffs.

In addition with respect to invoice charges related to the carbon tax that was implemented in July 2012, it was identified that:

 Carbon intensity charge rates were inconsistent with reported carbon emissions rates; and

 Carbon intensity rates used for carbon adjustment charges generally were around national benchmark measures which were above the benchmark measures reported for South Australia.

Levett & Sonnex Case Studies

The individual case studies that follow provide details of savings identified and achieved by the two participating businesses of approximately $70,000 per year:

 Levett Engineering: saved $16,000 p.a.

reducing the total bill by 17% from $95,000 to $79,000 per year by moving to an optimal network tariff.

 Sonnex Engineering: saved $54,000 p.a.

reducing the total bill by 30% from $181,000 to $127,000 per year by moving to an optimal network tariff and negotiating a lower Peak and Off-Peak energy price.

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Case Study – Levett Engineering

Levett Engineering Pty Ltd is an advanced parts manufacturer for aeronautical, defence, agriculture and other commercial industries. Levett manufactures for domestic and export markets (e.g. US & UK), including commercial and military aircraft parts, and component manufacture for the F35 Joint Strike Fighter aircraft program.

The Elizabeth South site currently operates 2 shifts per day over 5 days per week, but remains day shift dominant with a "skeleton" afternoon shift, employing 35 full time equivalent (FTE) personnel. The business is expected to grow to 3 shifts when the F35 Joint Strike Fighter aircraft manufacture moves to full production and the workforce is expected to grow to approximately 50 FTE. Major loads at the site include: milling machines & lathes.

The following table summarises the Levett electricity consumption for the 12 months ending 30 April 2013.

Source: Solstice

Load Characteristics

The Levett load fluctuates throughout the year with demand from the production schedule, which is evidenced from the Daily Max, Min & Average load data.

Excluding the Christmas holiday period & Easter, the maximum week day load ranged from around 60kW to 110kW over the 12 month sample period.

Analysis of the half hourly data shows that Levett is at or above 56kW load (50% of maximum load) for about 44% of the time, and uses the top 10% of its maximum load for only about 0.12% of the time.

Price Characteristics

The Levett cost of key elements including Peak and Off Peak electricity prices and carbon adjustment are comparable with Levett’s peers. Network costs however, whilst charged as a pass through at regulated rates appear relatively high with Levett on a Monthly Business 2 Rate network tariff.

Financial Year 2013 total electricity expenditure (excluding GST)

Total annual spend: $95,065 Average annual spend: $0.257/kWh

Source: Solstice

Statistic Units Value Note

Electricity consumption kWh pa 372,160

Peak Electricity consumption kWh pa 243,960 66%

Off Peak Electricity consumption kWh pa 128,200 34%

Maximum demand kW 111 at 09:30 on Tue 29 May 2012

Minimum demand kW 2 at 08:00 on Wed 26 Dec 2012

Average demand kW 42 Load Factor % 38% 0 20 40 60 80 100 120 D ai ly D e m an d ( kW )

Daily Maximum, Minimum & Average Load

Daily Max Load Daily Min Load Daily Average Load

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34

Peak Off Peak Average

Levett ce n ts p e r kW h

Grid Supply Total Charges (2013)

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Network Tariff Optimisation

An analysis of the network tariff showed that on current load assumptions, Levett would pay less in total electricity costs by applying to SAPN for a network tariff change request.

Based on the Monthly Business 2 tariff, the annual network charges were approximately $54,000.

Based on the Low Voltage Stepped Demand tariff, at a power factor of 0.84, the annual network charges would be approximately $38,000.

If Levett annual load fell below 225,000 kWh (all other things remaining the same), the Monthly Business 2 tariff would be optimal.

Source: Solstice

Result

SAPN accepted the Levett change request and changed the Levett network tariff from June 2013.

The estimated annual savings based on FY2013 regulated network tariffs of moving from the Monthly Business 2 Tariff to the Low Voltage Stepped Demand Tariff is approximately $16,000 per year.

Source: Solstice

As the chart shows, there is a significant decline in the average Peak rate that applies to Levett following the change in network tariff, but a significant increase in the Off Peak rate. However, the overall average unit price declines by 17% from 25.7 cents per kWh to 22 cents per kWh representing a total annual saving of $16,000 (FY2013 excluding GST) from an annual bill of $95,000 down to $79,000 per year.

$-$5,000 $10,000 $15,000 $20,000 $25,000 $30,000 $35,000 $40,000 $45,000 $50,000 $55,000 $60,000 N e tw o rk C o st s kWh

Network Options - Levett

Network Total (Business 2 Rate) Network Total (Low Voltage Stepped Demand)

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36

Peak Off Peak Average Peak Off Peak Average

Levett (B2R Network Tariff) Levett (VLVS Network Tariff)

ce n ts p e r kW h

Grid Supply Total Charges (2013)

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Case Study – Sonnex Engineering

Sonnex Engineering Pty Ltd provides precision plasma, laser & oxy profile cutting services to a diverse Australian domestic customer base. Some of this cutting equipment is very energy usage intensive.

The Elizabeth South site typically operates an 8 hour shift, 5 days per week with approximately 32 full time equivalent (FTE) personnel.

The following table summarises the Sonnex electricity consumption for the 12 months ending 30 April 2013.

Source: Solstice

Load Characteristics

The Sonnex load fluctuates throughout the year with demand from the production schedule, and includes a Christmas shutdown. Excluding Christmas, the Sonnex maximum load ranged from around 150kW to 300kW over the 12 month sample period.

Sonnex has a very low load factor of 20% (due to its non shift operations) and consumes 75% of its energy at peak times, which drives up the average cost of electricity. Half hourly load data shows that Sonnex is at or above 145kW load (50% of maximum load) for only about 17% of the time, and uses the top 10% of its maximum load for only about 0.05% of the time.

Price Characteristics

The Sonnex electricity rates were significantly above its peers at March 2013, and the total average rate and charging basis resembled what one would ordinarily see for a small to medium enterprise (SME) rather than an industrial customer.

In addition, network costs, whilst charged as a pass through at regulated rates appear relatively high with Sonnex on a Quarterly Business 2 Rate network tariff.

Financial Year 2013 total electricity expenditure (excluding GST)

Total annual spend: $180,833 Average annual spend: $0.339/kWh

Source: Solstice

Statistic Units Value Note

Electricity consumption kWh pa 519,151

Peak Electricity consumption kWh pa 390,053 75%

Off Peak Electricity consumption kWh pa 129,098 25%

Maximum demand kW 290 at 10:00 on Wed 12 Dec 2012

Minimum demand kW 10 at 05:00 on Sat 24 Nov 2012

Average demand kW 59 Load Factor % 20% 0 50 100 150 200 250 300 De m an d (k W )

Time of Day (Half Hour Ending)

Year - Work Day & Non Work Day Demand

Work Day Minimum Work Day Average Work Day Maximum Non Work Day Minimum Non Work Day Average Non Work Day Maximum

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44

Peak Off Peak Average

Sonnex

cents per kWh

Grid Supply Total Charges (2013)

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Network Tariff Optimisation

An analysis of the network tariff showed that on current load assumptions, Sonnex would pay less in total electricity costs by applying to SAPN for a network tariff change request.

Based on the Quarterly Business 2 tariff, the annual network charges were approx. $82,000. Based on the Low Voltage Stepped Demand tariff, at a power factor of 0.86, the annual network charges would be approximately $70,000.

However, if Sonnex annual load fell below 410,000 kWh (all other things remaining the

same), the Business 2 tariff would be optimal. Source: Solstice

Result

Sonnex took a 2 step approach to reducing its overall electricity costs in the second quarter of 2013. Firstly, Sonnex negotiated reduced Peak and Off Peak electricity rates with its Retailer for a new contract

commencing in April 2013. The revised rates recognised Sonnex as a significant customer, and are expected to save approximately $41,000 per year.

Secondly, Sonnex made a network change request application to SAPN to move from the Business 2 Tariff to the Low Voltage Stepped Demand Tariff, which is expected to save a further $1,000/month or approx. $12,000 per year.

Source: Solstice

The overall average unit price declines by 30% from 33.9 cents per kWh to 24.3 cents per kWh representing

estimated annual saving of $53,000 (FY2013 excluding GST) from an annual bill of $181,000 down to $127,000/year.

$-$10,000 $20,000 $30,000 $40,000 $50,000 $60,000 $70,000 $80,000 $90,000 $100,000 N e tw o rk C o st s kWh

Network Options - Sonnex

Network Total (Business 2 Rate) Network Total (Low Voltage Stepped Demand)

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 Retailer Invoice Mar 2013 Retailer Contract May 2013 Optimised Network Jul 2013 ce n ts p e r kWh

Sonnex Grid Supply Total Charges (2013)

Electricity price (excl Carbon)

$180,833 $139,843 $127,145 $40,991 $12,697 Tariff Savings Optimised Network New Contract