Statement of Corporate Intent 2013-2014 - Ergon Energy · Statement of Corporate Intent 2013-14 6...

Statement of Corporate Intent 2013-14


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Table of Contents

Introduction ............................................................................................................................................ 3

Objectives and Strategy .......................................................................................................................... 4

Financial and Shareholder .................................................................................................................... 12

Customer Driven ................................................................................................................................... 18

Asset Management Excellence ............................................................................................................. 21

High Performance Organisation............................................................................................................ 24

Financial Information ............................................................................................................................ 27

Other Obligations .................................................................................................................................. 36

Government Directions ......................................................................................................................... 37

PERFORMANCE AGREEEMENT ............................................................................................................. 38

ATTACHMENT 1: Employment and Industrial Relations Plans ............................................................. 39

ATTACHMENT 2: Sponsorship, Advertising, Corporate Entertainment, Donations and Other Arrangements ....................................................................................................................................... 51

Graphs and Tables

Graph 1: Maximum Allowable Revenue ................................................................................................. 5 Graph 2: Forecast Indicative Prices and Revenue per Customer ............................................................ 7 Graph 3: Ergon Energy – Comparison of Capital and Operating Expenditure to AER Distribution Determination ....................................................................................................................................... 12 Table 1: Capital Expenditure on Standard Control Services ................................................................. 13 Graph 4: Capital Expenditure on Standard Control Services Compared to AER Distribution Determination ....................................................................................................................................... 14 Table 2: Operating Expenditure ............................................................................................................ 15 Graph 5: Operating Expenditure on Standard Control Services Compared to AER Distribution Determination ....................................................................................................................................... 15 Graph 6: Demand Management Reduction Targets 2013-14 (Percentage of total MVA Target by programme type) .................................................................................................................................. 21 Graph 7: Total Number of Solar PV Connections .................................................................................. 22 Table 3: Financial Performance Indicators ............................................................................................ 27 Table 4: Dividends, Tax Equivalent Payments (TEPs) and Community Service Obligations (CSOs) ...... 28 Table 5: Financial Contributions: Major Business Divisions .................................................................. 28 Table 6: Key Assumptions ..................................................................................................................... 37 Table 7: Summary of Sponsorship, Advertising, Corporate Entertainment, Donations and Other Arrangements Budget and Actual Expenditure .................................................................................... 51

Note:

This document contains highly confidential material relating to the business affairs of Ergon Energy. Release of its contents is subject to the provisions of the Right to Information Act 2009. Any unauthorised disclosure of material contained in this statement may diminish the commercial value of that information and would have an adverse effect on the business, commercial and financial affairs of Ergon Energy.


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Introduction

This Statement of Corporate Intent (SCI) has been prepared in compliance with sections 102 and 105 of the Government Owned Corporations Act 1993 (the GOC Act) and applies to Ergon Energy Corporation Limited and its subsidiaries for the 2013-14 year. For the purposes of this SCI, Ergon Energy and its subsidiaries are referred to as Ergon Energy.

Ergon Energy is a regional electricity distribution entity and an electricity retailer within its franchise area of regional Queensland, as defined in the Queensland Electricity Act 1994 (the Electricity Act).

Ergon Energy builds, operates and maintains its electricity distribution network to ensure customers have an adequate, economic, reliable and safe supply of electricity. As the holder of a distribution authority, Ergon Energy provides network access to all customers within its region so they can connect their electrical installations.

Ergon Energy owns and operates a 55 megawatt (MW) gas-fired power station in Barcaldine, which supplies power to the state-wide electricity grid. It also has 33 stand-alone power stations that provide supply to customers in isolated communities that are not connected to the grid.

The main operating companies within the Ergon Energy Group and their activities are:

Ergon Energy Corporation Limited (EECL). EECL operates, maintains, develops and protects the electricity supply network to ensure the adequate, economic and safe supply of electricity to its customers.

Ergon Energy Queensland Pty Ltd (EEQ), a 100% subsidiary of EECL, is an electricity retailer to around 700,000 customers in regional Queensland.

EECL is a 100% shareholder in Ergon Energy Telecommunications Pty Ltd (EET). EET is a licensed telecommunications carrier providing high-speed data services to external customers on a commercial basis from spare Ergon Energy telecommunications capacity.

EECL is a 100% shareholder in ROAMES Asset Services Pty (dormant).

EECL is a 50% shareholder in SPARQ Pty Ltd (SPARQ). SPARQ is a company jointly owned with Energex and provides Information and Communications Technology (ICT) and telecommunication support.

Throughout the 2013-14 financial year Ergon Energy will continue to find innovative ways to reduce expenditure, and to increase the efficiency and effectiveness of all facets of the business.


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Objectives and Strategy

In accordance with section 17 of the GOC Act, the key objectives of Ergon Energy are to be commercially successful in the conduct of its activities and efficient in the delivery of its community service obligations. To fulfil these objectives, Ergon Energy needs to deliver an affordable, secure, reliable, efficient and safe electricity network that meets both industry standards and delivers value to customers.

In their Statement of Corporate Intent approval letter dated 21st December 2012, Ergon Energy’s shareholding Ministers requested the following:

Queensland Treasury has advised Ergon Energy that “well positioned” relates to progress towards restraining network revenue increases to CPI.

Ergon Energy’s key strategic objective was to limit increases in average network charges to 1% less than the CPI by the 2020 to 2025 regulatory period while still meeting our regulatory and customer service obligations. The significant softening of demand for electricity since the summer of 2010-11 has continued and this combined with efficiencies, new demand management solutions and benign economic conditions has enabled Ergon Energy to reduce the total expenditure in regard to its standard control services and isolated generation activities in the current regulatory period (2010 to 2015) by 19% or around $1.5 billion1.

Ergon Energy is expecting network revenue to decrease materially in 2015. This decrease results from an expectation that capital markets will remain stable, combined with the reduced expenditure in the current period and forecast stable (in inflation adjusted terms) network investment for the 2015 to 2020 period. A critical factor on reduced revenue flowing through to prices will also be maintaining consumption levels.

Ergon Energy has bought forward its key strategic objective to limit increases in average network charges to 1% less than the CPI subject to stable capital markets and energy consumption from the 2020-2025 period to the next regulatory control period 2015 to 2020.

Shared Objectives

As communicated to Ergon Energy, shareholders’ objectives are to reduce electricity prices, reduce debt, increase dividends and maintain customer service. Ergon Energy has also included reduce costs, efficient management of Community Service Obligations (CSO) and manage risk. Ergon Energy’s contribution to reducing electricity prices is through restraining network revenue growth, promoting efficient consumption and providing effective retail services.

1 Compared to the AER Distribution Determination for standard control capital and operating expenditure and

compared to the 2011/12 budget for isolated generation activities.


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While Ergon Energy forecasts that subject to stable capital markets network revenue (transport) is likely to drop in the next regulatory period, the same cannot be said about the energy side of the equation. The Renewable Energy Target if unchanged is expected to continue to have an upward influence, while the carbon price could have a downward influence, depending if European carbon markets remain low or should the Liberal National Party win federal government and rescind the federal carbon pricing mechanism.

Price versus Cost

Network revenue is set on the Maximum Allowable Revenue as determined by the Australian Energy Regulator (AER). This is varied each year based on any over or under recoveries of revenue, allowed pass throughs such as the costs in excess of allowances for the Solar Bonus Scheme (SBS) and an incentive payment or penalty for unplanned outage performance. To date, revenue requirements have been reduced by around $182 million under Shareholders directions to not pass through the Gamma Tax adjustment for 2011-12; Yasi incremental costs; and to reduce revenue as a result of savings from the Electricity Network Capital (ENCAP) review. Current modelling suggests that revenue will peak in 14-15 as shown in the following chart.

Graph 1: Maximum Allowable Revenue

Reducing prices in the current regulatory control period is challenging. Under the existing regulatory regime, Ergon Energy’s revenue is set by the AER at the start of a regulatory control period. This means that if Ergon Energy reduces its costs compared to what the AER allowed within a regulatory control period, the benefits are not passed on immediately to customers through lower network prices. Instead, adjustments are made at the beginning of the next regulatory control period to ensure customers share the benefit of any cost reductions made now. Any other adjustments to pricing arrangements can only be determined outside of the national electricity rules which govern Ergon Energy. In the current regulatory control period, for example, revenue was reduced as a result of the ENCAP review through a direction from shareholding Ministers.


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Ergon Energy has begun the process of preparing a proposal for the AER to determine our revenue allowance for the next regulatory control period (2015 to 2020) with very clear objectives around affordability, customer value, and prudent investment. An extensive stakeholder engagement programme has also been developed to ensure these objectives are well informed by customer requirements. The focus to date has been on ensuring the approach to forecasting future investment is consistent with customer needs. Ergon Energy has also begun its engagement with the AER on the framework and approach to setting prices for 2015 to 2020. The formal regulatory proposal will be submitted to the AER in October 2014.

The revenue allowance set by the regulator (which sets the network charges paid by customers) allows Ergon Energy to recover the costs of providing regulated network services. An appropriate revenue allowance is central to the economic sustainability of the business and long term price and service stability for customers.

Limiting increases to revenue requirements is dependent on Ergon Energy maintaining capital and operating expenditure at or below current levels. It is also dependent on future financing costs being lower than what was forecast for the current regulatory control period. If market expectations of lower financing costs eventuate, the revenue requirement is expected to be lower than the revenue requirement for the current regulatory control period.

A Once in a Generation Opportunity

The forecast reduction in revenue provides an opportunity to implement tariff reform while mitigating the impact on customers. Ergon Energy looks forward to working with government on tariff reform and to developing a pathway for network tariffs that will be sustainable, transparent and assist customers to make informed decisions. This will also support the development of pricing options which can reduce peak demand on the network and improve asset utilisation. The graph below shows indicative average network charges based on current forecasts of revenue to 2020.


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Graph 2: Forecast Indicative Prices and Revenue per Customer

Dropping Consumption is a High Risk to Prices and Business Value

Over recent years, electricity prices have risen and while our customers are largely satisfied with the level of electricity supply reliability, the price and affordability of electricity is now a major concern. The cost of electricity distribution is a large component of the final electricity price faced by our customers. Customers are changing behaviour with a focus on more careful energy use generally, but less so on hot days, so the gap between normal and peak energy demand may increase. The outcome is illustrated below:

A circuit breaker is required to protect business value.


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Ergon Energy Strategy

Ergon Energy’s key strategic objective is to limit increases in average network charges to 1% less than the CPI over 2015-2020 subject to stable capital markets and energy consumption. Another strategic objective is to maintain the business value. While the business value has grown substantially over the last decade this was due to investments to bring the asset up to a satisfactory condition, meet minimum customer service standards, progress towards compliance to security criteria established by government and meet the record growth of load and new connections in regional Queensland. This is not the environment we now operate in and product substitution, declining consumption and fixed cost recovery are real issues impacting value.

Achieving this strategic objective means that Ergon Energy is increasing its operational efficiency and reducing costs. Ergon Energy is also getting closer to its customers so it can better manage and influence their demands on the network to reduce the growth in peak demand, increase asset utilisation and reduce the need for further network augmentation.

The following illustration captures all the key elements of our strategy that together will drive us towards our objectives.


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Hierarchy of Reform.

There is a clear hierarchy when it comes to reform. Market reform is the most critical followed by regulatory, industry and business. An efficient market leads to less regulation and more efficient investment.

Ergon Energy operates within a regulatory, legislative and government policy environment that will have a strong influence on the achievement of the strategic objectives as illustrated in the diagram below. Ideally, the achievement of the strategic objective would be supported by an effective market, followed by prudent investment and then efficient delivery. Policy and regulatory changes are needed to deliver a more effective market and prudent investment resulting in better outcomes for customers.

Effective Market – responsibility for an effective

market rests largely with state and federal governments and

regulators

Prudent Investment – responsibility for prudent

investment rests largely with state government and with Ergon

Energy

Efficient delivery— Responsibility predominantly rests

with Ergon Energy.

Supply and demand trading: Government/AEMO

Minimum service standards: QCA/Government

Reduce costs: Ergon Energy

Tariff regulation removed: Government

Minimise network investment: Ergon Energy; Government (security standards)

Increase efficiency: Ergon Energy

Time of use tariffs: Government/QCA

Best solution: Ergon Energy Improve capability: Ergon Energy

Capacity charging: Government/QCA

Reduce WACC risk: Ergon Energy; QTC; AER

Workforce flexibility: Ergon Energy + Government

De-regulation: Government Competition: Ergon Energy

Choice: All


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Electricity Sector Reform

Over the 2012-13 year, the Queensland Government has undertaken a number of reviews which have examined the structure of the Queensland electricity sector and have sought to address rising electricity prices. The Queensland Commission of Audit reviewed the overall Government financial position and made recommendations in regard to improving the State’s financial position ensuring value for money in service delivery. On June 16 2013 the Government released the final reports from two key reviews of the electricity sector; the Interdepartmental Committee on Electricity Sector Reform (IDC) and the Independent Review Panel (IRP) on network costs. The Government also released its response to the recommendations in the IDC report.

These three reviews have been comprehensive and have involved all facets of the electricity sector within Queensland including the operation and structure of Ergon Energy. Ergon Energy understands that the final decisions arising from the reviews are a matter for Government and agrees that the Queensland electricity sector needs to be a viable, sustainable and competitive industry for the benefit of the State as a whole. Ergon Energy is committed to working with Government as it implements these reviews and to delivering a safe, reliable, efficient and affordable electricity supply to our customers across both the network and retail arms of the business.

The Government has announced in-principle approval of a recommendation for the establishment of a holding company to have ownership of Energex and Ergon Energy. Subject to the Government’s confirmation of this decision, Ergon Energy will work with the Queensland Government to consult on and implement the new holding company structure for Energex and Ergon Energy and to deliver associated efficiencies in operation.

Ergon Energy acknowledges that the Queensland Government has expressed a preference for any further targeted efficiencies and/or reductions in regulated capital expenditure to result in lower distribution service charges (lower than those which are otherwise provided for under the regulatory arrangements).

It is expected that explicit direction from shareholding Ministers would be received to give effect to any such requirement at the time that prices are set.


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Performance Objectives: 2013-14 to 2014-15

Financial & Shareholder

Network Charges - Limit increases in average network charges to 1% less than the Consumer Price Index (CPI) over 2015-2020 subject to stable capital markets and energy consumption.

Financial Targets - Consistently achieve financial results that meet or better our AER Distribution Determination. Achieve a commercial return on assets.

Core Business - Improved core business focus by divesting and outsourcing non-core activities.

Customer Driven

Service - Deliver quality, cost, value and choice by customer segment.

Customer Satisfaction - Maintain strong customer relationships and work with customers to identify and meet their future needs.

Asset Management Excellence

Demand Management - Reduce peak load growth by at least 100MW (122MVA) by 2015-16 to defer capital expenditure on our network.

Reliability - Meet minimum service standards and secure optimal Service Target Performance Incentive Scheme result.

Prudent & Efficient - Deliver the capital and operating expenditure programmes prudently and efficiently, meeting shareholder and customer requirements.

High Performance Organisation

Performance - Build a high performance organisation that is enabled by quick and simple access to spatially structured information to improve decision making.

Skills & Culture - Build a resilient, adaptable and efficient organisation with the skills and culture required to manage increasingly sophisticated networks, information systems and renewable energy solutions.

Safety - Make sustained progress towards "no one gets hurt today"; achieve safety results in the top quartile for our industry by 2015.


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Financial and Shareholder

In 2012-13 Ergon Energy conducted a detailed review of its forecasts and associated capital and operating expenditure budgets for the remaining three years of the current regulatory period. In September last year, Ergon Energy submitted a revised final 2012-13 SCI; budgeted capital expenditure at group level for 2012-13 was reduced to $901 million from $964 million, a decrease of $63 million and budgeted operating expenditure at group level for 2012-13 was reduced to $651.4 million, a decrease of $52.2 million. Ergon Energy met these targets for the 2012-13 year; actual capital expenditure at group level was $871.8 million and operating expenditure at group level was $641.2 million.

For the remainder of the current regulatory control period (2010 to 2015), Ergon Energy is focusing on ensuring its capital and operating expenditure takes into account the changes in the external environment and on improving the efficiency and effectiveness of the company as a whole. These changes are aimed at meeting shareholder Ministers’ performance expectations and also to help support the achievement of Ergon Energy’s goal of limiting increases in average network charges to 1% less than the CPI over 2015 to 2020 subject to stable capital markets and consumption.

Ergon Energy is forecasting to spend considerably less than its AER Distribution Determination. Over the total current five year regulatory control period to 2014-15, Ergon Energy is forecasting that capital plus operating expenditure on standard control services will be 18.5% under the AER allowance. Forecast total expenditure is expected to be 20.2% under the Distribution Determination in 2013-14 and 23.3% under in 2014-15.

Graph 3: Ergon Energy – Comparison of Capital and Operating Expenditure to

AER Distribution Determination

1,000.00

1,200.00

1,400.00

1,600.00

1,800.00

2010-11 2011-12 2012-13 2013-14 2014-15

Distribution Determination Capital and Operating Expenditure

Actual and Forecast Capital and Operating Expenditure

Forecast Expenditure is 20.2% under the Distribution Determination in 2013-14 and

23.3% under in 2014-15


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Key Priorities 2013-14

Regulated Capital Expenditure

In its September 2012 SCI, the Ergon Energy capital expenditure budget for standard control services was set at $820.1 million for the 2012-13 year. Actual capital expenditure on standard control services for 2012-13 was $798.2 million; a reduction of around 3% compared to the September 2012 SCI budget.

Table 1: Capital Expenditure on Standard Control Services2

Category 2012-13 Actual

$million

2013-14 Budget $million

Asset Replacement 278.4 249.3

Customer Initiated Capital Works 191.1 214.4

Corporation Initiated Augmentation 145.3 218.5

Reliability and Quality Improvements 24.4 25.4

Other System Capital Expenditure 64.7 55.2

Non-System Capital Expenditure 94.3 117.9

TOTAL REGULATED CAPITAL EXPENDITURE3 798.2 880.7

Asset Replacement: This is expenditure which is needed to replace network assets that are at risk of failure. The need for this work is determined both by actual asset failure and through the results of assessments made on the condition of assets as part of the overall asset inspection regime.

Customer Initiated Capital Works: This is work Ergon Energy does to extend the network and provide access so customers can connect to the network.

Corporation Initiated Augmentation: expenditure on the sub-transmission and distribution network in response to increasing network usage and demand from customers.

Reliability and Quality Improvements: Expenditure to improve the reliability and quality of supply for customers.

Other System: expenditure to improve communications, protection, the performance of the Single Earth Wire Return (SWER) network and undergrounding, as well as other programmes.

Non-System: Non-system capital expenditure supports the operation of Ergon Energy and includes items such as tools and equipment, fleet, property and IT systems.

Regulated capital expenditure for 2013-14 is budgeted to be $880.7 million, significantly below the AER distribution determination figure for 2013-14 of $1,146.1 million (see graph below). Asset replacement expenditure in 2012-13 was higher than forecast and augmentation projects were deferred. Work is underway to prevent this recurring in 2013-14. As a result, the 2013-14 budget for

2 Standard Control Services only

3 Totals may not add due to rounding


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corporation initiated augmentation has increased compared to 2012-13. Non-system capital expenditure is expected to increase by $23.6 million in 2013-14 compared to 2012-13 due to the commencement of expenditure on the site refurbishment at Glenmore Road, Rockhampton which is expected to be completed in 2014-15.

Graph 4: Capital Expenditure on Standard Control Services Compared to AER

Distribution Determination4

The budget does not include any allowance for summer storm activity. As occurred in 2012-13, Ergon Energy will attempt to manage any storm impacts within the budget allocations, but a severe weather event could make this challenging and expenditure may need to increase above budget allocations.

The lower capital expenditure has also reduced Ergon Energy’s debt requirements. This combined with a debt repayment plan means that Ergon Energy now expects its debt level at the end of the current regulatory control period to be around $1.1 billion lower than forecast at the start of the regulatory control period in 2010-11.

Operating Expenditure

Ergon Energy’s total operating expenditure for 2012-13 was $641.2 million, $10.2 million less than the September 2012 SCI budget of $651.4 million. This favourable result includes the impact of ex tropical cyclone Oswald which resulted in over $10.0 million of unbudgeted operating expenditure being required to restore the network.

4 Standard Control Services only

0

400

800

1,200

2010-11 2011-12 2012-13 2013-14 2014-15

$m

illio

ns

Distribution Determination Capital Expenditure

Actual and Forecast Capital Expenditure


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Table 2: EECL Operating Expenditure

Category 2012-13

Actual $000s

2013-14 Budget $000s

Regulated Operating Expenditure 452,956 411,976

Non-Regulated Operating Expenditure 810 1,024

Isolated Generation Operating Expenditure 84,401 67,299

External Works and Services 86,513 86,315

Regulated Operating Expenditure: expenditure (including net support costs) on the maintenance on the regulated asset base. It includes network operations as well as preventative, corrective and forced maintenance such as asset inspection, vegetation management, and work on the network that is required in response to events such as cyclones or flooding.

Non-Regulated Operating Expenditure: expenditure on the maintenance of non-regulated assets.

Isolated Generation Operating Expenditure: expenditure on the maintenance of Ergon Energy’s 33 stand-alone power stations which are primarily diesel generators and are not connected the distribution network.

Regulated operating expenditure for 2013-14 is budgeted to be $412.0 million, around $41.0 million less than 2012-13. This reflects in part, the cost savings that have been made particularly in network maintenance costs which includes preventative, corrective and forced maintenance on the network. For standard control services only, operating expenditure for 2013-14 is budgeted at $347.5 million5, $44.9 million less than the AER Distribution Determination amount for 2013-14 of $392.4 million.

Graph 5: Operating Expenditure on Standard Control Services Compared to AER

Distribution Determination6

5 Excludes Solar Bonus Scheme

6 Excludes Solar Bonus Scheme

0

200

400

2010-11 2011-12 2012-13 2013-14 2014-15

$m

illio

ns

Distribution Determination Operating ExpenditureActual and Forecast Operating Expenditure


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Ergon Energy will continue to carefully manage its operating expenditure with a focus on cost control and efficiency without reducing network performance or employee and community safety. However, achieving budget levels will remain challenging. As occurred in 2012-13, Ergon Energy will attempt to manage any storm impacts within the budget allocations, but a severe weather event could make this challenging and expenditure may need to increase above budget allocations.

Community Service Obligations

The Uniform Tariff Policy provides for parity of pricing for all non-market electricity consumers, regardless of their geographic location in the State. For customers outside of the south east corner, the cost of supply of electricity generally exceeds the price paid under the uniform tariff arrangement. The Queensland Government pays Ergon Energy a Community Service Obligation (CSO) to compensate for these costs.

For the year ended June 2013 this CSO payment was $596 million. Ergon Energy estimates that CSO revenue for the 2013-14 year will be approximately $607.3 million. This increase is due to a number of factors including an increase in network charges and energy purchases. This estimate could alter due to changes in the key components that contribute to the CSO such as customer load, customer numbers, and wholesale electricity prices. Ergon Energy is working with the Government to reduce the CSO and is also actively participating in a Government led CSO Review.

The CSO Deed has been extended and will expire on 30 June 2014.

Ergon Energy also receives a CSO in regard to pensioner rebates. This CSO is expected to be approximately $42.6 million in 2013-14 and is funded by the Department of Communities, Child Safety and Disability Services.


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Performance Targets: Financial and Shareholder

QUARTER 2013-14

2011-12 Actual

2012-13 Budget

2012-13 Actual

2013-14 Budget Sep Dec Mar Jun

300.4 329.2 368.5 351.7 EBITDA – Group Excluding EEQ ($M)

1,065.0 1,130.8 1,244.5 1,349.8

21.2 21.9 34.7 40.1 EBITDA – EEQ($M) 84.2 81.3 127.0 117.9

222.1 249.6 298.6 280.4 EBIT – Consolidated ($M) 777.8 815.4 980.1 1,050.7

92.2 104.7 141.3 129.3 NPAT – Consolidated ($M) 319.8 315.3 433.6 467.5

- - - - Return on Assets – Consolidated

7.6% 7.5% 8.9% 8.9%

- - - - Return on Assets –

Regulated 8.1% 8.4% 9.3% 9.8%


Non-Regulated 18.5% 12.9% 11.7% 7.4%


Group Excluding EEQ 7.2% 7.1% 8.2% 8.4%

- - - - Return on Equity – Consolidated

9.7% 9.0% 12.4% 12.2%

- - - - Opex per Route Kilometre 2,639 2,216 2,364 2,210

- - - - Actual Opex with Regulatory Allowance

42.0% 59.0% 60.0% 78.6%

- - - - Actual Capex with Regulatory Allowance

29.0% 44.0% 44.0% 59.5%

- - - - Network Maintenance Costs-RAB

3.3% 2.4% 2.70% 2.2%

Notes:

1. Return on Assets (%) = [EBIT-Average of opening & closing assets]. (Assets = "Total Assets") 2. Return on Equity (%) = [NPAT-Average of opening & closing equity] 3. The opex and capex numbers in this table are for standard control services only. The regulated asset base

(RAB) has been adjusted for the outcomes of the Merits Review process, but has not otherwise been

adjusted. The comparisons of opex and capex to the regulatory determination are calculated on a

cumulative basis to 2014-15.


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Customer Driven

Improving the affordability of electricity for our customers is at the centre of our strategy. This means Ergon Energy needs to have a good understanding of our customers’ needs and can offer them the right balance of products, service, cost and quality. Over 2013-14 Ergon Energy will review its network tariff strategy, continue to look for ways to improve efficiency and effectiveness across the organisation, and continue to deliver the level of reliability and service our customers need.


Network Tariff Strategy

In 2012-13 Ergon Energy began a review of its Network Tariff Strategy due to:

Rising electricity prices and affordability issues;

The increasing visibility of Ergon Energy’s network tariffs in the regulated retail electricity prices (or Notified Prices); and

Changes in our operating environment (e.g. advances in technology such as metering, data management and communication).

This objective of this work is to develop a network tariff strategy which clearly maps out a pathway for network tariffs that will be sustainable, transparent and assist customers to make informed decisions about their energy use. It is intended that this work will support the demand management plan over the medium term by developing pricing options for customers that can reduce peak demand on the network and improve asset utilisation. Over 2013-14 Ergon Energy will work with government to further progress this work consistent with government policy.

More flexible tariff arrangements are an important element to maintain business value and to improve the affordability of electricity over the medium to long term. The best outcomes for our shareholder, our customers and our business are most likely to be achieved through more effective markets of which tariff reform is a key enabler.

Ergon Energy will seek to pursue opportunities and collaborate with government and regulators to reform electricity markets so that customers are able to respond to signals reducing the cost of supply and the price of electricity. This is achieved through improved load factor and asset utilisation as a result of energy being consumed when the distribution network is not constrained and discouraging consumption in peak times when the distribution network is constrained. To be effective, market reform also needs to benefit customers by enabling them to choose options that best suit their needs. Over 2013-14 Ergon Energy will work with government to further progress this work consistent with government policy.

EEQ

In 2012-13, Ergon Energy put in place a new operational structure for its retail operations and established executive accountability for the retail business. This is the first step towards greater separation of the retail business and a step towards single point accountability. Once the structure for EEQ is finalised this separation will provide greater clarity of retail and customer service accountabilities and better management of risks arising from changes in the retail environment.

Over 2013-14, EEQ progress towards the achievement of its key objective; transforming EEQ into an “Agile Energy Retailer” with a focus on commerciality and results for customers, employees and shareholders. A key area of focus will be transitioning to a new CSO environment to more closely align EEQ’s revenue and costs to those of benchmark retail businesses. EEQ will also focus on better managing and understanding its customers to preserve value in the customer base and improve


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customer loyalty. During 2013/14 preliminary steps will be taken to enable both EEQ and EECL to position for full retail contestability. This will include building capability to allow retail and distribution functions to be unbundled from both EECL and EEQ, and beginning the transformation of existing customer information and management systems.

Efficiency and Effectiveness Programme

Ergon Energy began a company-wide efficiency and effectiveness programme in September 2011. The programme delivered strong results during 2012-13 and for the 2012-13 year, benefits7 were $113 million, exceeding the $50 million forecast in September 2012. This is a result of a range of initiatives that have reduced support costs and increased scrutiny of capital expenditure. In particular, the increase in benefits over the original forecast is due to reductions in overtime compared to the May 2012 budget, a reduction in recruitment and reductions in SPARQ’s capital expenditure.

Ergon Energy has begun the definition of the next phase of the programme. This next phase will maintain the existing benefits and expand the programme into the areas of capital optimisation, non-core asset optimisation, outsourcing and improving data and information. This next phase is at an early stage and the likely benefits have not yet been finalised. Work is underway to determine the likely benefits and Ergon Energy will continue to keep shareholding Ministers informed as this next phase is outworked.

Improving Network Reliability

Ergon Energy’s reliability performance has improved significantly; over the period from 2005-06 to 2012-13 the duration of unplanned outages has reduced by 31.0% and the frequency by 36.0%. The overall frequency and duration of outages in this period has also improved by 37.0% and 36.0% respectively. This improvement in network reliability reflects the significant investment and priority Ergon Energy has had over this period to achieving the regulated minimum network service standards.

For the 2012-13 year, Ergon Energy’s reliability performance has been better than the Electricity Industry Code’s Minimum Service Standards (MSS) for five of six measures. The overall network SAIDI performance for 2012-13 is favourable to the equivalent period for 2011-12 by 8.6% while the overall network SAIFI performance is favourable to the equivalent period for 2011-12 by 10.6%.

Ergon Energy has also performed well over 2012-13 in regard to the AER Service Target Performance Incentive Scheme (STPIS) with 5 out of 6 reliability performance measures favourable to the STPIS Targets. The 2012-13 STPIS financial outcome is based on performance for the various reliability measures and the customer service parameter (telephone answering). For 2012-13 the financial outcome from STPIS is a positive impact of $31.4 million.

Ergon Energy considers that overall network reliability is now delivering the level of service our customers expect and that care needs to be taken to ensure expenditure in this area continues to deliver customer value. Over 2013-14 Ergon Energy will continue to implement its reliability improvement plan and will work with government to agree ongoing Minimum Service Standards targets that effectively balance the objectives of price and reliability in line with the needs of our customers.

7 These benefits include reductions in capital, operating and overhead expenditure.


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Large Customer Connections

Improving the delivery of major projects for customers is a key challenge for Ergon Energy, and over 2013-14 Ergon Energy is seeking to better engage with customers at the pre-feasibility stage, provide alternatives for the design and construction of the projects and, if the customer does chooses Ergon Energy to do the work - having a clearly defined process for managing the project from enquiry through to commissioning. Over 2013-14 Ergon Energy will:

Utilise improved customer information and project probability data to improve forecasting of resource requirements and minimise network impacts from major customer projects; and

Establish a proven process and genuine market mechanisms to enable customers to choose a Build, Own and Operate, or a Build and Transfer model for establishing electrical infrastructure.

Performance Targets: Customer Driven

QUARTER 2013-14

2011-12

Actual

2012-13

Budget

2012-13

Actual

2013-14

Budget Sep Dec Mar Jun

29.88 45.39 44.26 29.47 Urban SAIDI 136 ≤147 135 ≤146

89.14 124.15 125.78 84.93 Short Rural SAIDI 393 ≤412 341 ≤406

183.33 343.60 267.23 169.84 Long Rural SAIDI 1,042 ≤932 952 ≤916

0.37 0.60 0.56 0.43 Urban SAIFI 1.41 ≤1.94 1.50 ≤1.92

0.80 1.24 1.10 0.82 Short Rural SAIFI 3.56 ≤3.85 3.00 ≤3.80

1.45 2.61 1.93 1.41 Long Rural SAIFI 7.02 ≤7.20 6.20 ≤7.10

>100 >100 >100 >100 Value to Customer 105

Better than peer average (>100)

105

Better than peer average (>100)

Notes:

1. SAIDI: System Average Interruption Duration Index. Average of the total duration (expressed in minutes) of interruptions of supply that customers experienced in the last 12 months. Categories, urban, short rural and long rural are based on feeder type.

2. SAIFI: System Average Interruption Frequency Index. Average of the number of interruptions of supply that customers experienced in the last 12 months. Categories, urban, short rural and long rural are based on feeder type.

3. The Value to Customer measure provides residential customer feedback on the value provided by Ergon Energy.

4. Totals may not add due to rounding.


21


Asset Management Excellence

Ergon Energy is focused on ensuring prudent asset management and realising greater value from its existing assets. Over 2013-14, Ergon Energy will continue its Joint Workings programme with Energex Limited, and will continue to implement its demand management programme. Ergon Energy will also continue its work to mitigate the impact of solar photovoltaic (PV) connections on network performance. Over 2013-14 Ergon Energy will work with government to implement the recommendations of the IDC in regard to the integration of energy planning into state and local government planning processes. Ergon Energy also welcomes the move towards improved coordination and consultation in regard to development projects by government departments as it should reduce the costs incurred by Ergon Energy and improve customer outcomes.


Demand Management

Ergon Energy’s Demand Management Programme is on track to deliver on the full regulatory control period target of 122MVA by June 2015. As at end of June 2013, 89.0% (109MVA) of the regulatory period target had been achieved. For 2012-13 47MVA of demand was offset against an annual target of 25MVA. Highlights of the demand reduction programme to date include:

22.0MVA of peak demand reduction achieved through the successful implementation of the Hot Water stage of North Queensland Load Harmonisation project;

9.4MVA of demand reduction achieved through the network support generation agreement for the Moranbah project;

5.1MVA of peak demand reductions from the Townsville NDM Pilot; and

5.4MVA of peak demand under load control from economy tariff switching.

For 2013-14, Ergon Energy estimates a demand management plan budget total of approximately $15 million with an annual demand reduction target of 24 MVA.

Graph 6: Demand Management Reduction Targets 2013-14 (Percentage of total

MVA Target by programme type)

Commercial & Industrial

29%

Load Harmonisation

29%

Other Broadbased

17%

Generation 8%

Economy Tariff

Switching 11%

Solar Cities

6%


22


Solar PV System Connections

At the end of June 2013, over 78,000 rooftop grid-connected PV systems had been installed in regional Queensland under the Solar Bonus Scheme (SBS), with an array (generation) capacity exceeding 247MW. Approximately, 18% of detached houses in regional Queensland now have a PV system; nearly 14% of all residential customers. Ergon Energy received approximately 31,000 applications to connect a solar PV system in the two weeks up to the end of the 44c Feed-in Tariff on 10 July 2012. Current figures indicate only around 55% of those customers ultimately had a system connected or increased the size of their existing system by the deadline of 30 June 2013.

The network’s ability to cope with a two-way flow of electricity has limits. As the number of PV connections to the network rises, capital expenditures higher than normal load growth would demand are required to mitigate performance impacts. In addition, PV systems generate electricity outside of typical peak consumption periods. This can have the perverse impact of reducing off-peak electricity usage, while increasing electricity usage in peak periods. Over time, as PV connections increase further, these effects may worsen and result in pressure to introduce smart grid technologies to better manage both customer demand and network performance. Work will continue over 2013-14 on trialling and implementing various technical solutions to voltage and other network impacts of PV systems.

Ergon Energy is a revenue capped business which enables a return on long-life fixed assets. As most revenue is recovered from consumption based prices the offsetting impact of PVs increases the unit price of energy for all customers.

Ergon Energy expects PV system connections to remain around 400 per week on average in 2013-14, compared to the 2012-13 average of around 620 per week.

Graph 7: Total Number of Solar PV Connections

0

20,000

40,000

60,000

80,000

100,000

120,000

Forecast


23


Joint Workings

Joint Workings is an ongoing programme of work being undertaken by Ergon Energy and Energex Limited. The objective of the programme is to work together to deliver asset management savings and benefits through a collaborative and shared cost approach. It is currently being transitioned to a business-as-usual activity. The programme of work for 2013-14 is expected to include:

Joint Asset Management Framework: This is a joint document structure to support joint workings and potentially one business model. It is aligned with the British Standards Institution Standard PAS 55:2008 - Optimal Management of Physical Assets. This work is currently underway and will assist with the supporting documentation required for next (2015-2020) Regulatory Submission.

Maintenance Framework: This is the alignment of Energex and Ergon Energy Asset Management Policy, Protocol, Maintenance Standards, Maintenance Activity Frequencies and Acceptance Criteria. The implementation of the framework is in progress for Substation and Lines assets.

Alignment: This is the alignment of standards, equipment and materials (where possible) e.g. modular sub stations, switchgear, lines and cables including alignment of standards for plant ratings, security of supply, load forecasting, network connections and many others. This alignment is expected to provide benefits in procurement, design, construction, commissioning and maintenance practices including resource sharing opportunities.

Strategic Sourcing Procurement and Logistics: This work is underway and involves the standardisation of specifications for plant and high volume-cost items to provide opportunities for savings through improved materials and increased volumes.

Performance Targets: Asset Management Excellence

Quarter 2013-14

2011-12

Actual

2012-13

Budget

2012-13

Actual

2013-14


- - - - Demand Reduction 41MVA 25MVA 47MVA 24MVA

400 1,200 1,200 1,200

GSL Incidents - Reliability – Number of Claims Accepted & Paid

2,942 3,000 3,928 4,000

41,000 123,000 123,000 123,000 GSL Incidents – Reliability – Amount Paid ($)

305,916 310,000 408,512 410,000

1,000 1,500 1,500 1,000 GSL Incidents – Other - Number of Claims Accepted & Paid

7,178 7,200 4,059 5,000

38,000 57,000 57,000 38,000 GSL Incidents – Other - Amount Paid ($)

270,981 270,000 164,203 190,000

Notes:

1. MVA: Megavolt ampere. The demand reduction targets are from the 2013-14 Ergon Energy Demand Management Plan which was submitted to the Department of Energy and Water Supply on 19 June 2013.

2. GSLs: Guaranteed Service Levels. Since 1 July 2010 Guaranteed Service Level payments have been made automatically. Forecasting GSLs is difficult, especially given the overall size of our network, the high proportion of overhead lines and the impact of weather events which can limit access and therefore our ability to restore supply. The dollar figures in the table above do not include overheads.


24


High Performance Organisation

To achieve its strategy Ergon Energy needs to ensure its people carry out their work safely and have the skills and support they need to deliver continuous improvement in service delivery and customer value. Over 2013-14 Ergon Energy will seek to: improve safety outcomes for our workforce and communities in regional Queensland; continue to review its organisational structure; divest its Remote Observation Automated Modelling and Economic Simulation (ROAMES) project; and implement its property strategy. All of these priorities will assist Ergon Energy to become a more effective and efficient organisation.


Health and Safety

Ergon Energy remains committed to ensuring the health and safety of our people and our communities. Ergon Energy’s All Injury Frequency Rate (AIFR) has improved from 14.07 in December 2010 to 7.80 for the year ended June 2013. Over 2013-14, Ergon Energy will continue to strengthen its positive safety culture. Key programmes will include:

Executive and senior leadership team safety leadership initiatives;

Focusing initiatives on the high risk areas of high voltage network switching, motor vehicle driving and electrical work;

The continuation and revision of the Comprehensive Safety Indicator (CSI) to proactively focus on a wider range of lead indicator safety inputs;

Further development of the Health Safety and Environment Risk Governance Framework the use of graphical tools to assess risk tolerability;

Further development, trial and implementation of the behavioural and cognitive safety initiative;

The promotion of the Health and Wellbeing portal and leveraging the Queensland Government Workplace for Wellness Initiative to provide further proactive health management programmes to assist employees to manage their own health; and

Further utilisation of the manual handling risk assessment tool to review hazardous manual tasks such as applying and removing portable earthing devices and loading and unloading trucks as a key initiative to address manual handling issues.

Organisational Review

Ergon Energy’s capital and operating expenditure is significantly below that allowed for in Ergon Energy’s current AER Distribution Determination. As a result, Ergon Energy announced in October 2012 that it would reduce staff numbers by 500 positions. This reduction is being implemented while ensuring the programme of work continues to be delivered efficiently and that the safety of employees, the community and the network is not compromised.

Ergon Energy is reviewing its organisational structure to improve accountability and performance and reduce costs. Much of this work is now completed; some business units have completed their re-structuring processes and others are in process of finalising structures and implementing the required changes. At the end of the 2011-12 year, Ergon Energy had 4,869 full time equivalent (FTE) employees. By the end of June 2013 Ergon Energy had 4,435 FTE employees, a reduction of 434 FTE employees. Over 2013-14 Ergon Energy will continue to right size the organisation by critically assessing the operating model and associated responsibilities. Any roles that become vacant will also be critically assessed and filled only where there is a critical business need.


25


Ergon Energy will maintain front line services to meet customer service, operational and regulatory requirements, through the use of internal and external resources (where appropriate) to manage cost and risks. However the number of resources required, including front line will be dependent on the workload and not historical resourcing levels. Importantly, resource levels will be maintained to ensure the same high standard of disaster response Ergon Energy has delivered in recent major recovery efforts.

The no forced redundancy provisions of the Ergon Energy Union Collective Agreement (EEUCA) will continue to apply to employees covered by the Agreement: this is approximately 97% of employees. The EEUCA expires in October 2014 and will continue to apply beyond the nominal expiry date until replaced or terminated in accordance with the requirements of the Fair Work Act 2009.

Remote Observation Automated Modelling and Economic Simulation (ROAMES)

ROAMES provides Ergon Energy with a visual 3D model of the Ergon Energy network and its surrounding environment which is expected to reduce costs, reduce risk and improve customer service. A customised aerial vehicle equipped with specialised sensor systems is used to fly the network. The data captured is then processed into 3D spatial information using sophisticated algorithms. This information can be used for example to identify where vegetation is encroaching on the network.

In 2013-14 Ergon Energy will seek to divest ROAMES in accordance with the approval given by shareholding Ministers through a sale of shares in a corporatised entity (ROAMES Asset Services Pty) which will be established to hold the ROAMES business.

Property Services

Ergon Energy's property strategy is focused on achieving the most cost effective accommodation solutions by co-locating and minimising the total number of leases while providing a safe working environment for our employees. Key to the current focus is reducing both operating and future capital expenditure in line with shareholder requirements.

Consistent with its property strategy, over 2012-13 Ergon Energy consolidated its accommodation arrangements in Brisbane moving from the CBD to the new building in Fortitude Valley. All Brisbane office staff (aside from ROAMES) are now working in a single location. Furniture and equipment from the 61 Mary St and Eagle Farm offices will be reused at other Ergon Energy sites throughout the State where it is deemed efficient, suitable and safe.

The Townsville property strategy is focused on consolidating the existing seven Townsville sites to two main properties. The white collar workforce will be consolidated into a single leased site in the Townsville CBD with relocation of employees expected to occur in the second half of the 2013 calendar year after practical completion of this newly constructed facility. The blue and near-blue collar workforce will be accommodated via a re-development of the existing Garbutt site to meet operational requirements and address safety concerns in the current over-crowded location.

Over 2013-14 Ergon Energy will manage its property capital programme of work to ensure it is supporting and contributing to the overall reduction in capital and operating expenditure for the remainder of this regulatory period. This includes the consolidation of staff and sites, where possible, and a focus on ensuring all expenditure is prudent and efficient.


26


Performance Targets: High Performance Organisation

PERFORMANCE TARGETS

2011-12

Actual

2012-13

Budget

2012-13

Actual

2013-14

Budget

AIFR - Employees 9.90 11.99 7.80 11.39

CCFR – Employees 2.00 3.31 2.30 3.30

LTIFR – Employees 2.70 2.3 2.60 2.2

LTIFR – Contractors 1.80 3.0 2.20 2.8

Environment – EPA Breaches (number of Class 1) 0 0 0 0

Staff Turnover (annualised) 8.10% n/a 14.30% n/a

Net FTE Staff Numbers 4,869 n/a 4,435 n/a

Timely compliance with government and shareholder data submission and reporting requirements

100% 100% 100% 100%

Notes:

1. AIFR = All Injury Frequency Rate. AIFR is the frequency rate of the number of injuries per million hours worked on a rolling twelve month basis ‘All Injuries’ is made up of Lost Time Injuries and Medical Treatment Injuries.

2. CCFR = Compensable Claims Frequency Rate. CCFR is the number of accepted employee compensation claims per 100 employees. CCFR= (Compensable Claims x 100)/(Total Personnel).

3. These targets have been set to give a sustainable glide path for Ergon Energy to be in the top quartile for safety performance in the industry by 2015.

4. Staff Turnover is reflective of the number of employees (permanent and fixed term) who have terminated during the period.

5. Net FTE Numbers are fixed term and permanent employees only and excludes casual employees.


27


Financial Information

The financial information shown below represents Ergon Energy’s best estimate of expected financial performance for the 2013-14 year at the time of preparation of this SCI.

Table 3: Financial Performance Indicators

Quarter 2013-14

2011-12

Actual

2012-13

Budget

2012-13

Actual

2013-14


3.0 2.9 2.9 3.1 Cost Recovery Ratio – Consolidated

3.0 2.8 2.9 3.0

31.6% 33.0% 36.0% 36.7% Operating Sales Margin - Consolidated

28.3% 28.2% 32.1% 34.4%

3.5% 3.3% 4.8% 6.1% Operating Sales Margin (%) – EEQ

3.7% 3.3% 5.1% 4.4%

13.5% 14.2% 17.4% 17.3% Profit Margin (%) –Consolidated

13.5% 12.0% 15.8% 16.4%

56.3% 56.7% 55.8% 56.3% Gearing Ratio (times) - Consolidated

59.3% 56.5% 57.3% 56.3%

49.0% 50.3% 49.7% 48.0% Debt to PPE (%)- Consolidated

52.0% 46.5% 49.7% 48.0%

- - - - Economic Profit – Consolidated

206.1 253.9 376.8 393.6

0.9 1.2 1.3 1.0 Current Ratio (times) – Consolidated

1.0 0.8 0.8 1.0

0.7 1.0 1.1 0.9 Quick Ratio - Consolidated

0.8 0.7 0.7 0.9

2.5 2.5 3.1 2.9 Interest Cover (EBIT times)

2.4 2.2 2.7 2.7

3.6 3.5 4.2 4.1 Interest Cover (EBITDA Times) - Consolidated

3.6 3.3 3.7 3.8

3.5 3.4 4.0 5.0 Funds from Operation (FFO) interest cover (times) – Consolidated

3.3 3.2 3.0 4.0

- - - - Fixed Asset Turnover -Consolidated

0.2 0.2 0.2 0.2

0.7 0.7 0.6 0.7 Capital Ratio -Consolidated

0.7 0.7 0.7 0.7


28


Table 4: Dividends, Tax Equivalent Payments (TEPs) and Community Service

Obligations (CSOs)

2011-12 Actual $000s

2012-13 Budget $000s

2012-13 Actual $000s

2013-14 Budget $000s

Dividends Provided for 255,853 252,202 325,764 374,002

CSO's 415,218 607,715 596,413 607,270

Tax Provided for 136,796 135,108 177,398 200,358

Table 5: Financial Contributions: Major Business Divisions

SUBSIDIARY Nature of Business

EBIT Contribution to Group Financial Outcome

2012-13

Actual

$000s

2013-14

Budget

$000s

EECL Network Supply and

Maintenance and Business Development

913,452 1,012,864

Ergon Energy Queensland (EEQ)

Retail Franchise Business 124,505 113,465

Ergon Energy Telecommunications (EET)

EET trading as Nexium Telecommunications is a licensed carrier offering

wholesale high-speed data capacity in regional

Queensland.

3,799 4,991

Eliminations -61,646 -80,641

ERGON GROUP EBIT 980,110 1,050,679


29


FINANCIAL STATEMENTS

Ergon Energy Group

Statement of Comprehensive Income Actual SCI Actual Budget

Sept Dec Mar Jun Ergon Energy Group 2011-12 2012-13 2012-13 2013-14

$'000s $'000s $'000s $'000s $'000s $'000s $'000s $'000s

ENERGY RELATED REVENUE

416,900 458,949 542,090 484,223 Energy Sales 1,598,088 1,687,196 1,694,827 1,902,162

7,545 40,848 (21,164) (24,889) Unbilled Energy Sales 3,518 0 19,911 2,339

33 33 33 33 Guarantee Deficiencies 282 420 156 132

143,616 119,484 173,620 170,550 CSO Revenue 415,218 607,715 596,413 607,270

0 0 0 0 Renewable Energy Revenue 38 158 18 0

0 0 0 0 Mark to Market Revenue (5,073) 0 0 0

1,459 2,126 2,081 1,958 Meter Cards Revenue 6,349 6,542 6,981 7,625

88,429 92,889 93,426 91,817 DUOS 277,022 354,007 320,447 366,562

0 0 0 0 Current Year DUOS Alignment 61,592 0 21,482 0

0 0 0 0 Current Year STPIS Alignment 0 0 26,050 0

0 0 0 0 Current Year Solar FiT Alignment 0 0 72,372 0

(460) (460) (460) (460) Prior Year STPIS Alignment 0 13,530 13,530 (1,838)

(7,991) (7,991) (7,991) (7,991) Prior Year DUOS Alignment 30,217 (21,050) (25,730) (31,964)

415 415 415 415 Prior Year Shared Asset Alignment (5,184) 0 0 1,661

(18,380) (18,380) (18,380) (18,380) Prior Year Caps Cons Alignment 17,416 (50,920) (50,878) (73,519)

18,618 18,618 18,618 18,618 Prior Year Solar FiT Alignment 0 0 27,808 74,472

(24,179) (24,179) (24,179) (24,179) Solar Bonus 0 (60,000) (75,404) (96,716)

2,042 2,261 2,521 2,345 Diesel Fuel Rebate 10,528 9,415 10,132 9,168

0 0 0 0 Mark to Market Net Sales 0 0 37,728 0

628,047 684,613 760,632 694,062 TOTAL ENERGY RELATED REVENUE 2,410,012 2,547,013 2,695,843 2,767,354

COST OF SALES

92,886 112,095 149,741 121,115 Energy Purchases 252,739 493,357 577,523 475,837

0 0 0 0 Energy Brokerage Fees 449 0 496 0

0 0 0 0 Hedge Costs Realised 165,655 0 (48,934) 0

23,126 27,243 17,478 14,904 Certificate Compliance Expenses 77,794 91,872 95,020 82,750

0 0 0 0 Contestable Charges Recoverable 44 0 0 0

78,178 81,920 87,098 82,081 Transmission Charges 306,017 316,806 305,653 329,278

727 830 870 745 Market Charges 3,147 3,252 2,976 3,172

878 958 989 892 Ancillary Charges 3,280 3,422 2,184 3,717

21 21 21 21 Metering Charges Non-Recoverable 75 84 91 84

17,747 13,639 6,604 5,956 Embedded Energy 16,519 35,568 26,078 43,947

7,611 9,276 9,220 9,105 Isolated Energy 27,580 32,085 33,731 35,213

0 0 0 0 Loss on Sale Environmental Products 45 0 (459) 0

221,176 245,982 272,022 234,818 TOTAL COST OF SALES 853,344 976,446 994,358 973,998

406,871 438,631 488,609 459,244 ELECTRICITY GROSS MARGIN 1,556,668 1,570,567 1,701,485 1,793,356

OTHER PRODUCT REVENUE

25,617 24,186 22,653 24,857 Sales Revenue 71,689 98,907 97,353 97,314

1,231 1,231 1,231 1,231 Non-Energy Purchases 5,229 5,346 4,326 4,923

24,387 22,955 21,423 23,627 NON ENERGY RELATED GROSS MARGIN 66,460 93,561 93,027 92,390

MISCELLANEOUS REVENUE

2,203 2,159 2,113 2,136 Interest 19,090 14,820 17,200 8,612

1,481 1,460 1,392 1,381 Interest on MOFA 5,983 6,025 5,902 5,714

0 0 0 0 Government Grants - Solar cities 339 1,292 0 0

0 0 0 0 Government Grants - Demand Management 6,556 7,273 2,039 0

162 162 162 163 Rent 920 690 1,306 650

0 0 0 0 Gain on Sale of Assets 2,286 2,366 2,401 0

13,900 13,900 13,900 13,900 Capital Contributions - Cash 43,274 59,786 47,431 55,600

3,775 3,775 3,775 3,775 Capital Contributions - Non-Cash 11,460 14,000 20,094 15,100

15,000 15,000 15,000 15,000 Capital Contributions - AARR Alignment 61,066 50,000 56,261 60,000

3,320 3,320 3,320 3,320 Alternative Control 19,236 18,952 26,868 13,281

179 249 266 112 Large Customer Connection 7,091 18,210 4,680 806

0 0 0 0 Street Lighting 1,337 0 324 0

779 779 779 779 Corporate Service Fees 3,685 3,547 3,585 3,117

0 0 0 0 Discounts Received 16,973 0 24,456 0

0 0 0 0 CAC Revenue 131 0 0 0

621 621 621 621 Other Revenue 6,756 2,321 5,704 2,483

0 0 0 0 Inter-Company Other Revenue 0 0 0 0

41,421 41,426 41,328 41,187 TOTAL MISCELLANEOUS REVENUE 206,183 199,282 218,252 165,363

472,680 503,011 551,360 524,058 GROSS MARGIN & OTHER REVENUE 1,829,311 1,863,411 2,012,764 2,051,109

151,049 151,934 148,186 132,227 Opex 680,065 651,366 641,240 583,396

151,049 151,934 148,186 132,227 TOTAL OPERATING EXPENSES 680,065 651,366 641,240 583,396

OTHER OPERATING EXPENDITURE

97,205 99,071 102,340 109,464 Depreciation 363,434 392,462 380,671 408,081

2,373 2,371 2,238 1,971 Amortisation 8,033 4,159 10,744 8,953

99,578 101,442 104,578 111,436 TOTAL OTHER OPERATING EXPENDITURE 371,467 396,620 391,415 417,034

222,053 249,635 298,596 280,396 EARNINGS BEFORE INTEREST & TAXES (EBIT) 777,779 815,425 980,110 1,050,679

90,404 100,111 96,689 95,613 Finance Charges 321,166 365,063 369,097 382,8180 0 0 0 Inter-Company Finance Charges 0 0 0 0

131,649 149,523 201,906 184,783 EARNINGS BEFORE TAXES (EBT) 456,613 450,362 611,012 667,861

39,495 44,857 60,572 55,435 Income Tax 136,796 135,108 177,398 200,358

92,154 104,666 141,334 129,348 NET PROFIT AFTER TAXES (NPAT) 319,816 315,254 433,615 467,503

701,183 793,337 898,003 1,039,338 OPENING RETAINED EARNINGS 450,338 615,227 514,302 701,183

0 0 0 42,361 Adjustment for Super Surplus 0 0 79,031 42,361

793,337 898,003 1,039,338 1,211,046 TOTAL AVAILABLE FOR APPROPRIATION 770,155 930,481 1,026,947 1,211,046

0 0 0 374,002 Dividends Provided For 255,853 252,202 325,764 374,002

0 0 0 374,002 TOTAL DIVIDENDS 255,853 252,202 325,764 374,002

793,337 898,003 1,039,338 837,044 CLOSING RETAINED EARNINGS 514,302 678,279 701,183 837,044

Quarter 2013-14


30


Statement of Financial Position Actual SCI Actual Budget


$'000s $'000s $'000s $'000s $'000s $'000s $'000s $'000s

179,389 51,960 98,804 167,880 Cash & Cash Equivalents 437,923 224,668 195,117 167,880

649,814 719,304 779,369 804,427 Current Receivables 489,482 456,374 649,132 804,427

125,200 136,250 141,250 143,450 Inventories 99,083 103,353 110,250 143,450

92,768 92,768 92,768 92,768 Financial Assets Current 77,383 77,383 92,768 92,768

0 0 0 0 Intangibles Current 0 0 0 0

43,447 45,695 47,996 40,485 Other Current Assets 40,959 37,841 40,026 40,485

1,090,617 1,045,977 1,160,186 1,249,010 CURRENT ASSETS 1,144,830 899,619 1,087,293 1,249,010

232,858 132,928 51,423 98,176 Long Term Receivables 220,543 175,815 311,310 98,176

0 0 0 0 Non-Current Investments 0 0 0 0

2,400 2,400 2,400 2,400 Non-Current Inventories 2,318 2,499 2,400 2,400

10,157,970 10,305,185 10,453,105 10,702,663 Property, Plant & Equipment 9,221,348 9,994,692 10,011,975 10,702,663

3 3 3 3 Deferred Tax Equivalent Assets 1 3,019 3 3

22,813 20,442 18,204 16,233 Intangible Non-Current 13,779 12,958 25,186 16,233

23,974 23,974 23,974 23,974 Superannuation Surplus 0 0 23,974 23,974

0 0 0 0 Other Non Current Assets 0 0 0 0

10,440,017 10,484,931 10,549,108 10,843,447 NON-CURRENT ASSETS 9,457,989 10,188,983 10,374,848 10,843,447

11,530,635 11,530,908 11,709,294 12,092,457 ASSETS 10,602,819 11,088,602 11,462,141 12,092,457

307,586 317,619 337,573 304,114 Current Payables 320,399 336,646 342,769 304,114

324,644 269,555 209,660 275,296 Interest Bearing Liabilities Current 262,331 245,675 324,450 275,296

70,416 70,416 70,416 70,416 Financial Liabilities Current 72,668 72,668 70,416 70,416

29,363 27,422 27,660 25,626 Current Provisions 37,419 41,701 28,873 25,626

133,127 131,262 133,649 136,044 Employee Benefits Current 162,901 148,552 130,741 136,044

325,764 (932) (932) 373,070 Dividends 255,853 252,202 325,764 373,070

69,547 77,881 86,704 60,392 Other Current Liabilities 70,705 57,786 61,074 60,392

1,260,447 893,223 864,730 1,244,958 CURRENT LIABILITIES 1,182,276 1,155,230 1,284,087 1,244,958

13,743 13,836 13,929 14,022 Employee Benefits Non-Current 18,259 18,783 13,608 14,022

1,646 1,646 1,646 1,646 Payables Non-Current 1,091 1,091 1,646 1,646

4,678,873 4,941,831 5,007,557 4,883,922 Interest Bearing Liabilities Non-Current 4,554,732 4,642,732 4,679,019 4,883,922

1,757,591 1,757,591 1,757,591 2,010,959 Deferred Tax Equivalent Liabilities 1,447,177 1,628,852 1,757,591 2,010,959

5,217 5,167 5,061 5,077 Non-Current Provisions 5,116 5,655 5,054 5,077

5,728 5,559 5,389 5,220 Other Non Current Liabilities 0 0 5,897 5,220

6,462,798 6,725,629 6,791,173 6,920,846 NON-CURRENT LIABILITIES 6,123,530 6,364,268 6,462,815 6,920,846

7,723,245 7,618,852 7,655,904 8,165,804 LIABILITIES 7,305,806 7,519,498 7,746,902 8,165,804

2,294,582 2,294,582 2,294,582 2,294,582 Share Capital 2,294,582 2,294,582 2,294,582 2,294,582

(1,352,190) (1,352,190) (1,352,190) (1,352,190) Unissued Capital (1,352,190) (1,352,190) (1,352,190) (1,352,190)

942,392 942,392 942,392 942,392 Contributed Equity 942,392 942,392 942,392 942,392

2,082,232 2,082,232 2,082,232 2,157,788 Asset Revaluation 1,850,893 1,959,007 2,082,232 2,157,788

(10,572) (10,572) (10,572) (10,572) Government Contribution Reserve (10,572) (10,572) (10,572) (10,572)

2,071,661 2,071,661 2,071,661 2,147,216 Reserves 1,840,321 1,948,435 2,071,660 2,147,216

766,107 766,107 766,107 766,107 Retained Profits 594,061 758,950 658,024 766,107

91,921 196,587 337,922 93,268 Current Year Profit 63,963 63,051 107,850 93,268

(64,692) (64,692) (64,692) (22,331) Ret Earn DB Super Surplus/Deficit (143,722) (143,722) (64,692) (22,331)

793,337 898,003 1,039,338 837,044 Retained Earnings 514,302 678,279 701,183 837,044

3,807,389 3,912,056 4,053,390 3,926,653 EQUITY 3,297,015 3,569,106 3,715,235 3,926,653

Quarter 2013-14

Cash Flow Actual SCI Actual Budget


$'000s $'000s $'000s $'000s $'000s $'000s $'000s $'000s

CASH FLOWS FROM TRADING ACTIVITIES

659,718 717,838 677,075 735,046 Receipts from Customers 2,305,398 2,305,709 2,274,052 2,789,677

(503,221) (517,180) (480,280) (449,382) Payments to Suppliers & Employees (1,766,929) (1,781,369) (1,854,084) (1,950,063)

3,685 3,619 3,505 3,518 Interest Received 25,073 20,845 23,102 14,326

(90,404) (100,111) (96,689) (95,613) Interest and Other Costs of Financing (311,161) (365,063) (356,274) (382,818)

13,900 13,900 13,900 13,900 Capital Contributions 43,274 59,786 47,431 55,600

143,616 119,484 173,620 170,550 Community Service Obligations 415,218 607,715 578,474 607,270

0 0 0 0 Dividends Received 0 0 0 0

0 0 0 0 Tax Paid 0 0 0 0

227,293 237,549 291,131 378,018 NET CASH PROVIDED BY OPERATING ACTIVITIES 710,873 847,623 712,702 1,133,991

CASH FLOWS FROM INVESTING ACTIVITIES


(243,200) (246,286) (250,259) (251,085) Land and Property Plant & Equipment (852,408) (901,066) (871,537) (990,831)

0 0 0 0 Intangibles - Software (10,579) 0 0 0

(243,200) (246,286) (250,259) (251,085) NET CASH USED IN INVESTING ACTIVITIES (781,990) (898,701) (864,225) (990,831)

CASH FLOWS FROM FINANCING ACTIVITIES

0 380,000 64,000 0 Proceeds from Borrowings 482,448 528,000 528,000 444,000

0 (171,938) (58,190) (58,635) Repay Borrowings 0 (440,000) (365,000) (288,763)

180 (57) 162 778 Repayable Deposits 0 5,675 1,570 1,062

0 (326,696) 0 0 Dividends Paid (252,640) (255,853) (255,853) (326,696)

180 (118,691) 5,971 (57,857) NET CASH PROVIDED BY FINANCING ACTIVITIES 229,808 (162,178) (91,283) (170,397)

(15,728) (127,429) 46,843 69,076 NET INCREASE/(DECREASE) IN CASH HELD 158,690 (213,255) (242,807) (27,237)

195,117 179,389 51,960 98,804 CASH HELD BEGINNING OF PERIOD 279,232 437,923 437,923 195,117

179,389 51,960 98,804 167,880 CASH HELD AT END OF PERIOD 437,922 224,669 195,117 167,880

Quarter 2013-14


31


Ergon Energy Corporation Limited


Sept Dec Mar Jun Ergon Energy Corporation Limited 2011-12 2012-13 2012-13 2013-14

$'000s $'000s $'000s $'000s $'000s $'000s $'000s $'000s



88,429 92,889 93,426 91,817 DUOS 277,022 354,007 320,447 366,562

360,741 388,518 426,248 392,162 Inter-Company DUOS 1,184,857 1,348,278 1,342,110 1,567,670

0 0 0 0 Current Year DUOS Alignment 61,592 0 21,482 0

0 0 0 0 Current Year STPIS Alignment 0 0 26,050 0

0 0 0 0 Current Year Solar FiT Alignment 0 0 72,372 0

(460) (460) (460) (460) Prior Year STPIS Alignment 0 13,530 13,530 (1,838)

(7,991) (7,991) (7,991) (7,991) Prior Year DUOS Alignment 30,217 (21,050) (25,730) (31,964)

415 415 415 415 Prior Year Shared Asset Alignment (5,184) 0 0 1,661

(18,380) (18,380) (18,380) (18,380) Prior Year Caps Cons Alignment 17,416 (50,920) (50,878) (73,519)

18,618 18,618 18,618 18,618 Prior Year Solar FiT Alignment 0 0 27,808 74,472

(24,179) (24,179) (24,179) (24,179) Inter-Company Solar Bonus (27,986) (60,000) (75,775) (96,716)

22,364 24,187 26,691 24,441 Inter-Company GUOS 117,000 118,311 111,781 97,682

2,042 2,261 2,521 2,345 Diesel Fuel Rebate 10,528 9,415 10,132 9,168


COST OF SALES

78,178 81,920 87,098 82,081 Transmission Charges 306,017 316,806 305,653 329,278

0 0 0 0 Inter-Company Meter Charges Non-Recoverable 453 0 417 0

0 0 0 0 Embedded Energy 354 0 140 0

218 218 218 218 Inter-Company Compensation Retail 297 486 706 870

78,395 82,138 87,316 82,299 TOTAL COST OF SALES 307,121 317,292 306,916 330,148

363,205 393,741 429,594 396,490 ELECTRICITY GROSS MARGIN 1,358,380 1,394,280 1,486,341 1,583,030


23,454 22,022 20,490 22,694 Sales Revenue 93,179 90,584 91,189 88,660

0 0 0 0 InterestDistrict Sales 255 0 751 0

0 0 0 0 Non-Energy Purchases 138 0 64 0

23,454 22,022 20,490 22,694 NON ENERGY RELATED GROSS MARGIN 93,296 90,584 91,876 88,660


731 697 681 689 Interest 10,241 8,182 8,410 2,798

1,481 1,460 1,392 1,381 Interest on MOFA 5,983 6,025 5,902 5,714

0 0 0 80,426 Inter-Company Dividends 59,833 56,319 61,419 80,426

0 0 0 0 Government Grants - Solar Cities 339 1,292 0 0

0 0 0 0 Government Grants - Demand Management 6,556 7,273 2,039 0

162 162 162 163 Rent 920 690 1,306 650


13,900 13,900 13,900 13,900 Capital Contributions - Cash 43,274 59,786 47,431 55,600

3,775 3,775 3,775 3,775 Capital Contributions - Non-Cash 11,460 14,000 20,094 15,100

15,000 15,000 15,000 15,000 Capital Contributions - AARR Alignment 61,066 50,000 56,261 60,000

3,066 3,066 3,066 3,066 Alternative Control 18,188 18,548 25,710 12,262

255 255 255 255 Inter-Company Alternative Control 1,219 404 1,249 1,018

179 249 266 112 Large Customer Connection 7,091 18,210 4,680 806

0 0 0 0 Street Lighting 1,337 0 324 0

7,555 7,825 8,631 8,089 Interdistrict Street Lighting 30,031 30,500 30,003 32,100

779 779 779 779 Corporate Service Fees 3,685 3,547 3,585 3,117

0 0 0 0 Discounts Received 16,825 0 24,432 0

12,444 11,756 11,874 11,820 Inter-Company SLA Revenue EEQ 49,571 49,735 47,029 47,894

731 731 731 731 Inter-Company SLA Revenue EETL 2,254 2,864 2,149 2,924

0 0 0 0 Interdistrict SLA Revenue EERA 0 172 0 0

0 0 0 0 Interdistrict SLA Revenue EERO 0 2,970 0 0

0 0 0 0 Other Revenue 4,779 520 4,366 0


446,717 475,417 510,596 559,370 GROSS MARGIN & OTHER REVENUE 1,788,613 1,819,393 1,927,008 1,992,101

147,489 147,394 143,292 128,439 Opex 667,079 629,195 624,680 566,614



97,162 98,900 101,938 108,740 Depreciation 363,408 391,487 380,640 406,740

1,604 1,604 1,471 1,204 Amortisation 6,616 2,281 8,236 5,882

98,766 100,504 103,409 109,944 TOTAL OTHER OPERATING EXPENDITURE 370,024 393,768 388,876 412,622

200,462 227,519 263,896 320,987 EARNINGS BEFORE INTEREST & TAXES (EBIT) 751,509 796,429 913,452 1,012,864

89,820 99,331 95,454 94,651 Finance Charges - Additional Items 318,313 362,504 365,743 379,257

52 60 49 53 Inter-Company Finance Charges 1,680 0 226 215


33,177 38,438 50,518 43,757 Income Tax 111,700 113,282 140,525 165,890


560,679 638,092 727,781 845,655 OPENING RETAINED EARNINGS 336,492 501,614 400,456 560,679

0 0 0 42,361 Adjustment for Super Surplus 0 0 79,031 42,361

638,092 727,781 845,655 1,070,543 TOTAL AVAILABLE FOR APPROPRIATION 656,309 822,257 886,443 1,070,543

0 0 0 374,002 Dividends Provided For 255,853 252,202 325,764 374,002

0 0 0 374,002 TOTAL DIVIDENDS 255,853 252,202 325,764 374,002

638,092 727,781 845,655 696,541 CLOSING RETAINED EARNINGS 400,456 570,055 560,679 696,541

Quarter 2013-14


32




$'000s $'000s $'000s $'000s $'000s $'000s $'000s $'000s



125,200 136,250 141,250 143,450 Inventories 99,083 103,353 110,250 143,450

70 70 70 70 Other Current Assets 86 86 68 70

688,925 616,125 694,398 894,269 CURRENT ASSETS 809,614 633,704 676,006 894,269

232,858 132,928 51,423 98,176 Long Term Receivables 220,543 177,911 311,310 98,176

2,498 2,498 2,498 2,498 Non-Current Investments 2,498 2,498 2,498 2,498

2,400 2,400 2,400 2,400 Non-Current Inventories 2,318 2,499 2,400 2,400

10,154,361 10,295,443 10,434,634 10,672,960 Property, Plant & Equipment 9,219,070 9,974,157 10,010,932 10,672,960

19,724 18,120 16,650 15,446 Intangible Non-Current 9,080 6,798 21,328 15,446

23,974 23,974 23,974 23,974 Superannuation Surplus 0 0 23,974 23,974

0 0 0 0 Other Non Current Assets 0 0 0 0

10,435,815 10,475,363 10,531,579 10,815,454 NON-CURRENT ASSETS 9,453,509 10,163,863 10,372,442 10,815,454

11,124,740 11,091,488 11,225,977 11,709,723 ASSETS 10,263,123 10,797,567 11,048,448 11,709,723



29,123 27,182 27,418 25,376 Current Provisions 36,756 40,908 28,476 25,376

133,127 131,262 133,649 136,044 Employee Benefits Current 162,901 148,552 130,741 136,044

325,764 (932) (932) 373,070 Dividends 255,853 252,202 325,764 373,070


1,050,133 664,361 615,431 1,043,063 CURRENT LIABILITIES 983,626 999,850 1,051,234 1,043,063

13,743 13,836 13,929 14,022 Employee Benefits Non-Current 18,259 18,783 13,608 14,022

1,646 1,646 1,646 1,646 Payables Non-Current 1,091 1,091 1,646 1,646

0 0 0 0 Tax Related Intercompany Payable 0 0 0 0

4,678,873 4,941,831 5,007,557 4,883,922 Interest Bearing Liabilities Non-Current 4,554,732 4,642,732 4,679,019 4,883,922

1,710,599 1,710,599 1,710,599 1,963,967 Deferred Tax Equivalent Liabilities 1,413,178 1,594,621 1,710,599 1,963,967


0 0 0 0 Superannuation Deficit 97,155 67,155 0 0

5,728 5,559 5,389 5,220 Other Non Current Liabilities 0 0 5,897 5,220

6,413,000 6,675,832 6,741,376 6,871,049 NON-CURRENT LIABILITIES 6,086,867 6,327,374 6,413,017 6,871,049

7,463,133 7,340,192 7,356,807 7,914,112 LIABILITIES 7,070,493 7,327,224 7,464,251 7,914,112

2,294,582 2,294,582 2,294,582 2,294,582 Share Capital 2,294,582 2,294,582 2,294,582 2,294,582

(1,352,190) (1,352,190) (1,352,190) (1,352,190) Unissued Capital (1,352,190) (1,352,190) (1,352,190) (1,352,190)

942,392 942,392 942,392 942,392 Contributed Equity 942,392 942,392 942,392 942,392

2,082,232 2,082,232 2,082,232 2,157,788 Asset Revaluation 1,850,893 1,959,007 2,082,232 2,157,788

(1,110) (1,110) (1,110) (1,110) Government Contribution Reserve (1,110) (1,110) (1,110) (1,110)

2,081,123 2,081,123 2,081,123 2,156,679 Reserves 1,849,783 1,957,897 2,081,122 2,156,679


77,180 166,869 284,743 93,268 Current Year Profit 63,963 68,441 81,193 93,268

(64,790) (64,790) (64,790) (22,429) Ret Earn DB Super Surplus/Deficit (143,820) (143,820) (64,790) (22,429)

638,092 727,781 845,655 696,541 Retained Earnings 400,456 570,055 560,679 696,541

3,661,607 3,751,296 3,869,170 3,795,611 EQUITY 3,192,631 3,470,344 3,584,193 3,795,611

Quarter 2013-14


33




$'000s $'000s $'000s $'000s $'000s $'000s $'000s $'000s



(294,574) (303,989) (297,087) (223,928) Payments to Suppliers & Employees (1,058,743) (878,726) (1,003,893) (1,119,578)


(89,872) (99,392) (95,504) (94,704) Interest and Other Costs of Financing (310,064) (362,504) (353,146) (379,472)

13,900 13,900 13,900 13,900 Capital Contributions 43,274 59,786 47,431 55,600

0 61,055 0 0 Dividends Received 70,448 59,833 59,833 61,055

0 0 0 37,485 Other Operating Receipts 25,042 25,097 27,365 37,485

0 0 0 0 Other Operating Payments 0 0 0 0

0 0 0 0 Tax Paid 0 0 0 0

213,689 305,954 267,082 333,446 NET CASH PROVIDED BY OPERATING ACTIVITIES 641,444 863,536 745,453 1,120,172



(240,592) (239,982) (241,129) (239,129) Land and Property Plant & Equipment (852,262) (890,966) (871,076) (960,831)


0 0 0 0 Other Investments 0 0 0 0

(240,592) (239,982) (241,129) (239,129) NET CASH USED IN INVESTING ACTIVITIES (779,103) (888,601) (863,764) (960,831)


0 380,000 64,000 0 Proceeds from Borrowings 479,930 528,000 528,000 444,000

0 (171,938) (58,190) (58,635) Repay Borrowings 0 (440,000) (365,000) (288,763)

0 0 0 0 Repayable Deposits 0 0 0 0

0 (326,696) 0 0 Dividends Paid (252,640) (255,853) (255,853) (326,696)

0 0 0 0 Issue of Shares 0 0 0 0

0 (118,634) 5,810 (58,635) NET CASH PROVIDED BY FINANCING ACTIVITIES 227,290 (167,853) (92,853) (171,459)

(26,902) (52,661) 31,763 35,682 NET INCREASE/(DECREASE) IN CASH HELD 89,630 (192,918) (211,164) (12,118)



Quarter 2013-14


34


Ergon Energy Queensland Ltd


Sept Dec Mar Jun Ergon Energy Queensland 2011-12 2012-13 2012-13 2013-14

$'000s $'000s $'000s $'000s $'000s $'000s $'000s $'000s


416,900 458,949 542,090 484,223 Energy Sales 1,598,088 1,687,196 1,694,827 1,902,162

7,545 40,848 (21,164) (24,889) Unbilled Energy Sales 3,518 0 19,911 2,339

33 33 33 33 Guarantee Deficiencies 282 420 156 132

143,616 119,484 173,620 170,550 CSO Revenue 415,218 607,715 596,413 607,270


0 0 0 0 Mark to Market Revenue (5,073) 0 0 0

1,459 2,126 2,081 1,958 Meter Cards Revenue 6,349 6,542 6,981 7,625

(24,179) (24,179) (24,179) (24,179) Solar Bonus 0 (60,000) (75,312) (96,716)

68 68 68 68 Inter-Company TUOS Contribution Acknow Rebate 453 246 417 270

0 0 0 0 Mark to Market Net Sales 0 0 37,728 0


COST OF SALES

92,886 112,095 149,741 121,115 Energy Purchases 252,739 493,357 577,523 475,837

22,364 24,187 26,691 24,441 Inter-Company Energy Purchases 117,000 118,311 111,781 97,682

0 0 0 0 Energy Brokerage Fees 449 0 496 0

0 0 0 0 Hedge Costs Realised 165,655 0 (48,934) 0

23,126 27,243 17,478 14,904 Certificate Compliance Expenses 77,794 91,872 95,020 82,750

0 0 0 0 Contestable Charges Recoverable 44 0 0 0

344,117 372,164 410,701 376,072 Inter-Company Contestable Charges Recoverable 1,186,931 1,318,778 1,296,573 1,503,054

727 830 870 745 Market Charges 3,147 3,252 2,976 3,172

878 958 989 892 Ancillary Charges 3,280 3,422 2,184 3,717

21 21 21 21 Metering Charges Non-Recoverable 75 84 91 84

17,747 13,639 6,604 5,956 Embedded Energy 16,165 35,568 25,938 43,947

7,611 9,276 9,220 9,105 Isolated Energy 27,580 32,085 33,731 35,213

0 0 0 0 Loss on Sale Environmental Products 45 0 (459) 0

509,479 560,412 622,316 553,250 TOTAL COST OF SALES 1,850,903 2,096,730 2,096,920 2,245,456

35,962 36,915 50,233 54,514 ELECTRICITY GROSS MARGIN 167,932 145,547 184,201 177,625


0 0 0 0 Sales Revenue (27,847) 0 (0) 0

255 255 255 255 Inter-Company Non-Energy Purchases 1,219 404 1,249 1,018

0 0 0 0 Non-Energy Purchases 0 0 0 0

(255) (255) (255) (255) NON ENERGY RELATED GROSS MARGIN (29,066) (404) (1,249) (1,018)


1,472 1,463 1,432 1,447 Interest 8,849 6,637 8,790 5,814

255 255 255 255 Alternative Control 1,048 404 1,159 1,018

0 0 0 0 Discounts Received 148 0 24 0

150 150 150 150 Inter-Company SLA Revenue 0 240 0 600

0 0 0 0 CAC Revenue 131 0 0 0

621 621 621 621 Other Revenue 1,977 1,802 1,338 2,483


38,205 39,149 52,436 56,732 GROSS MARGIN & OTHER REVENUE 151,317 154,225 194,968 186,522

16,997 17,289 17,761 16,600 Opex 67,115 72,939 67,929 68,647

Opex - Additional Items



43 171 402 725 Depreciation 26 342 31 1,341

767 767 767 767 Amortisation 1,412 1,215 2,503 3,069

810 939 1,169 1,492 TOTAL OTHER OPERATING EXPENDITURE 1,438 1,557 2,534 4,410

20,398 20,922 33,505 38,640 EARNINGS BEFORE INTEREST & TAXES (EBIT) 82,764 79,730 124,505 113,465

584 780 1,235 962 Finance Charges - Additional Items 2,853 2,559 3,354 3,561

0 0 0 0 Inter-Company Finance Charges 0 0 0 0


5,944 6,042 9,681 11,303 Income Tax 23,591 23,151 35,982 32,971


39,181 53,051 67,150 89,739 OPENING RETAINED EARNINGS 12,771 12,771 12,771 39,181

0 0 0 0 Adjustment for Super Surplus 0 0 0 0

53,051 67,150 89,739 116,113 TOTAL AVAILABLE FOR APPROPRIATION 69,091 66,791 97,941 116,113

0 0 0 76,933 Inter-Company Dividends Provided For 56,319 54,020 58,760 76,933

0 0 0 76,933 TOTAL DIVIDENDS 56,319 54,020 58,760 76,933

53,051 67,150 89,739 39,181 CLOSING RETAINED EARNINGS 12,771 12,771 39,181 39,181

Quarter 2013-14


35




$'000s $'000s $'000s $'000s $'000s $'000s $'000s $'000s



92,768 92,768 92,768 92,768 Financial Assets Current 77,383 77,383 92,768 92,768

43,377 45,625 47,926 40,415 Other Current Assets 40,873 37,755 39,958 40,415

656,842 625,505 679,101 627,630 CURRENT ASSETS 547,058 521,712 648,468 627,630

3,609 9,742 18,471 29,703 Property, Plant & Equipment 2,278 6,936 1,044 29,703

0 0 0 0 Deferred Tax Equivalent Assets 0 0 0 0

3,088 2,321 1,554 786 Intangible Non-Current 4,692 3,477 3,855 786

6,697 12,063 20,024 30,489 NON-CURRENT ASSETS 6,970 10,413 4,899 30,489

663,539 637,568 699,125 658,119 ASSETS 554,028 532,124 653,367 658,119



70,416 70,416 70,416 70,416 Financial Liabilities Current 72,668 72,668 70,416 70,416

241 240 242 250 Current Provisions 663 793 397 250

0 0 0 0 Employee Benefits Current 0 0 0 0

58,760 364 364 77,296 Dividends 56,319 54,020 58,760 77,296


466,333 426,263 465,230 474,782 CURRENT LIABILITIES 410,485 388,581 470,030 474,782

46,992 46,992 46,992 46,992 Deferred Tax Equivalent Liabilities 33,750 33,750 46,992 46,992


49,797 49,797 49,797 49,797 NON-CURRENT LIABILITIES 36,414 36,414 49,797 49,797

516,130 476,060 515,028 524,580 LIABILITIES 446,899 424,995 519,828 524,580

0 0 0 0 Share Capital 0 0 0 0

0 0 0 0 Unissued Capital 0 0 0 0

0 0 0 0 Contributed Equity 0 0 0 0

94,358 94,358 94,358 94,358 Government Contribution Reserve 94,358 94,358 94,358 94,358

94,358 94,358 94,358 94,358 Reserves 94,358 94,358 94,358 94,358


13,870 27,969 50,558 0 Current Year Profit 0 0 26,409 0

0 0 0 0 Ret Earn DB Super Surplus/Deficit 0 0 0 0

53,051 67,150 89,739 39,181 Retained Earnings 12,771 12,771 39,181 39,181

147,409 161,508 184,097 133,539 EQUITY 107,130 107,130 133,539 133,539

Quarter 2013-14



$'000s $'000s $'000s $'000s $'000s $'000s $'000s $'000s



(546,464) (599,668) (591,155) (596,224) Payments to Suppliers & Employees (1,954,441) (2,225,561) (2,209,555) (2,333,510)


(584) (780) (1,235) (962) Interest and Other Costs of Financing (2,778) (2,559) (3,354) (3,561)

0 0 0 0 Capital Contributions 0 0 0 0

143,616 119,484 173,620 170,550 Community Service Obligations 415,218 607,715 578,474 607,270

0 0 0 (36,345) Tax Paid (25,042) (23,591) (25,861) (36,345)

13,603 (10,009) 24,049 44,572 NET CASH PROVIDED BY OPERATING ACTIVITIES 136,476 58,242 23,569 72,216


(2,609) (6,304) (9,130) (11,957) Land and Property Plant & Equipment (147) (5,000) (461) (30,000)


(2,609) (6,304) (9,130) (11,957) NET CASH USED IN INVESTING ACTIVITIES (1,790) (5,000) (461) (30,000)


0 0 0 0 Proceeds from Borrowings 2,518 0 0 0

180 (57) 162 778 Repayable Deposits 0 5,675 1,570 1,062

0 (58,397) 0 0 Dividends Paid (68,143) (56,319) (56,319) (58,397)

180 (58,454) 162 778 NET CASH PROVIDED BY FINANCING ACTIVITIES (65,625) (50,644) (54,750) (57,334)

11,174 (74,767) 15,080 33,394 NET INCREASE/(DECREASE) IN CASH HELD 69,061 2,598 (31,642) (15,119)



Quarter 2013-14


36


Other Obligations

Dividend Policy

The dividend process is governed by the GOC Act and the Corporations Act 2001 (Cth). The board will ensure that Ergon Energy’s dividend policy also takes into account the return its shareholders expect on their investments. Ergon Energy’s policy is to recommend and pay a dividend amount equivalent to 80% (or the percentage approved by shareholding Ministers, if different) of Ergon Energy’s adjusted consolidated profit for 2013-14. The board adopts such a policy on the basis of its shareholders agreeing to provide the necessary funding for projects which have received board and shareholding Ministers’ approval or for the maintenance of Ergon Energy’s approved capital structure or for ensuring the operational viability of Ergon Energy. Ergon Energy’s board undertakes to adhere to the dividend policy.

Capital Structure

The Board will prudently manage the financing of Ergon Energy’s existing business and new business developments. As an integral part of the financing of the Corporation, the capital structure will be managed to ensure that Ergon Energy maintains a credit rating which aligns with the AER benchmark credit rating for Queensland Distribution Network Service Providers (DNSP) as published in periodic Rate of Return Guidelines or other rating as directed by shareholding Ministers. Ergon Energy’s Board will ensure Ergon Energy complies with this.

Equity contributions will be sought from shareholders if required to maintain alignment between the AER’s benchmark credit rating for Queensland DNSPs and Ergon Energy's current stand-alone investment grade credit rating as provided by Standard and Poor’s in their rating report of July 2012. As of the current date, forecasting indicates that Ergon Energy will not require an equity injection from its shareholding Ministers within the current five year Corporate Plan period which extends to 2017-18. However, the Board of Ergon Energy will continue to monitor the stand-alone credit rating of the company and will seek shareholder support for an equity injection if future forecasts indicate that it is required to maintain a credit rating which aligns with the AER’s Distribution Determination for DNSPs.

Investment Thresholds

Ergon Energy will seek shareholding Ministers’ approval for unregulated capital projects above $10 million and regulated capital projects above $75 million. Ergon Energy will work with the Department of Energy and Water Supply to ensure all remote generation capital expenditure can be brought forward to the Cabinet Budget Review Committee for approval.

Government Policy

The Queensland Government has expressed a preference for any further efficiencies and/or reductions in capital expenditure to result in lower distribution service charges (lower than those which otherwise are provided for under the regulatory arrangements). To the extent that Ergon Energy delivers such further efficiencies, it is expected that an explicit direction to that effect from shareholding Ministers will be received at the time that prices are set in 2014-15 and subsequent years.


37


Government Directions

2011 Electricity Network Capital Programme Review (ENCAP)

On 11 February 2012, Ergon Energy received a direction from shareholding Ministers under section 115 (1) of the GOC Act in regard to the implementation of the findings and recommendations of the ENCAP review. This direction required Ergon Energy to identify and quantify the annual revenue associated with the expected reduction in capital expenditures resulting from the implementation of the recommendations of the ENCAP review. Further, the direction required that Ergon Energy not seek to recover this revenue either over the remainder of the current Distribution Determination period or in any future period. Over the period to 2014-15 the expected reduction in revenue arising from this direction is expected to be approximately $99 million. The capital expenditure and financial statements included in this SCI are consistent with this direction.

EEQ

In May 2013, a direction under the Electricity Act was given to implement new wholesale electricity supply arrangements for Ergon Energy’s retail electricity load. The new market-based wholesale energy procurement arrangements will be implemented for a term of up to four years from 2013-14.

Carbon Offsets

In February 2013, a direction was received removing the requirement to purchase carbon offsets as per the Queensland Government Air Travel Policy, QFleet Climatesmart Action Policy and the Sport and Recreation Policy. This enables estimated annual savings of approximately $33,600.

Key Assumptions

The following table shows the key assumptions made by Ergon Energy in the preparation of this SCI.

Table 6: Key Assumptions

2011-12 Actual

2012-13 Forecast

2012-13 Actual

2013-14 Forecast

Consumer Price Index1 2.5% 2.5% 2.5% 2.5%

Wages Growth 3.5% 3.5% 3.5% 3.5%

Long Term Interest Rates 7.29% 7.34% 7.33% 7.39%

Dividend Payout Ratio2 80% 80% 80% 80%

Maximum Demand (MW) 3 2,417 2,559 2,380 2,592

Number of Customers 704,554 712,854 717,089 730,402 Notes:

1. CPI actual is from the Australian Bureau of Statistics. CPI forecasts are from the Reserve Bank of Australia. 2. The dividend is calculated at an amount equivalent to 80% of Ergon Energy’s adjusted consolidated profit. 3. The maximum demand forecast figures are from Ergon Energy’s system maximum demand model and are

temperature corrected (50% Probability of Exceedance: 50 POE). Actual Maximum Demand is the actual maximum demand on the network for the relevant year.

4. The customer numbers are those used to develop Ergon Energy’s 2013-14 pricing proposal

PERFORMANCE AGREEEMENT

This Statement of Corporate Intent (SCI), for the financial year 2013-14, is presented in accordance

with Chapter 3, Part 8 of the Government Owned Corporations Act 1993 (the GOC Act).

In accordance with Chapter 1, Part 3, Section 7 of the GOC Act, the SCI represents a formal

performance agreement between the Board of Ergon Energy and its shareholding Ministers with

respect to the financial and non-financial performance targets specified for the financial year. The

SCI also represents an acknowledgment and agreement on major activities, the objectives,

undertakings, policies, investments and borrowings of Ergon Energy for the 2013-14 year.

This SCI is consistent with Ergon Energy's Corporate Plan 2013-14 to 2017-18, submitted to, and

agreed to by, the shareholding Ministers in accordance with Chapter 3, Part 7 of the GOC Act.

In signing the document Ergon Energy's Board undertakes to achieve the targets proposed in this SCI

for 2013-14.

Major changes to key assumptions and outcomes detailed in this SCI, and which come to Ergon

Energy's attention during the year, will be brought to the attention of shareholding Ministers. Any

modifications to this SCI will be dealt with in accordance with the GOC Act.

This SCI is signed by the Chairman on behalf of all the Directors in accordance with a unanimous

decision of the Board of Ergon Energy.

Malcolm Hall-Brown

Chairman �- �o 13Date: '2 4 i B- ( l �

�. / /; j'#.........�...��Tim Nicholls MP

Treasurer and Minister for Trade

Date: 211,/1,Minister for Enerry and Water Supply

Date: I P (J,{ (t,&


39


ATTACHMENT 1: Employment and Industrial Relations Plans

Ergon Energy Employment and Industrial Relations Plan8

Shareholder Information

1. Employment and Industrial Relations Philosophy and Direction

Ergon Energy’s vision is to be a world class, customer driven energy business. This vision will be achieved by enhancing the economic and lifestyle aspirations of our customers through sustainable energy solutions. Our success in achieving our vision is underpinned by an organisational culture built on our values of Safety, Professionalism, Integrity, Respect, Innovation and Teamwork.

Our strategic employee relations goal is to foster effective and productive working relationships with our internal and external stakeholders, thereby developing a workplace reputation that underpins our commitments to our customers and the general public and which also meets our community service obligations.

2. Significant and Emerging Issues

There is growing customer and community concern over increasing energy costs. In response, the Queensland Government has formed an Interdepartmental Committee on Electricity Sector Reform (IDC) with the objective of ensuring electricity in Queensland is delivered in a cost-effective manner for consumers and that Queensland has a viable, sustainable and competitive electricity industry. The IDC has initiated an Independent Review Panel (IRP) to oversee the reform of power delivery by government-owned electricity entities in Queensland, with a particular focus on rising electricity prices. The review involves Ergon Energy, Energex, and Powerlink and is looking at opportunities to structure the industry to be more cost efficient and to reduce the upward pressure on electricity prices.

The IDC will make recommendations to Government regarding delivery of its objectives in relation to network costs, based on a report by the IRP. The implementation of resulting recommendations will be a significant challenge to the corporation and the industry in 2013-2014 financial year.

To meet this challenge and in response to a decrease in electricity demand, our capital and operational expenditure and our works delivery plan will be reduced by 1.2 billion dollars for the remaining regulatory period.

In 2013, Ergon Energy will finalise a strategic enablement program and whole of organisation workforce resource assessment initiated in 2012. These activities will restructure the organisation’s processes and resources to more efficiently deliver the reduced works delivery plan. Further to baseline efficiency savings in works delivery, the restructuring process (combined with retrenchment programs) aims to realise an FTE headcount reduction of 500 by 30 June 2013. The efficiency drive and restructuring process will continue throughout 2013-2014 financial year.

Ergon Energy will also continue the focus on delivering savings from the enterprise agreement productivity measures.

8 Note: The contents of the Ergon Energy Employment and Industrial Relations Plan 2013 are accurate as at the

time of preparation and final consultation undertaken in March 2013.


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3. Directors-Senior Executive Remuneration

Ergon Energy Corporation Limited (EECL): Senior Executive Remuneration as at 1 July 2012

Name of Incumbent

Position Title Base

Salary

Employer Superannuation

Contributions

Motor Vehicle

Car Park

Other Personal Benefits

Total Fixed Remuneration

Other Non-Personal Benefits

Performance Payment Made (1)

Ian McLeod Chief Executive $698,519 $16,470 $0 $0 $0 $714,989 $0 $77,858

Philip Keogan

Executive General

Manager Energy

Sustainability & Market

Development

$297,560 $16,470 $0 $0 $0 $314,030 $0 $38,971

Peter Billing

Executive General

Manager Operations

$358,005 $16,470 $0 $0 $0 $374,475 $0 $46,833

Justin Fitzgerald

Executive General

Manager Customer & Stakeholder Engagement

$266,407 $26,640 $0 $0 $0 $293,047 $0 $38,542

Mal Leech

Executive General

Manager Employee &

Shared Services

$311,100 $28,010 $0 $0 $0 $339,110 $0 $42,310

John Hooper

Chief Financial Officer

$354,823 $16,470 $0 $0 $0 $371,293 $0 $49,030

Graeme Finlayson

General Counsel- Company Secretary

$306,599 $16,470 $0 $0 $0 $323,069 $0 $42,356

Roslyn Baker

Executive General

Manager Retail

$271,150 $16,470 $0 $0 $0 $287,620 $0 $31,630

Neil Lowry

Executive General

Manager Asset Management

$310,776 $31,077 $0 $0 $0 $341,853 $0 $38,660

Brian Iwaszczyn

Executive General

Manager Major Projects

$333,530 $16,470 $0 $0 $0 $350,000 $0 $0

Notes:

(1) This is the actual performance payment made for the financial year 2011-2012. Performance payment was not applicable to Executive General Manager Major Projects as commencement was effective 2 July 2012.


41


ERGON ENERGY EMPLOYMENT AND INDUSTRIAL RELATIONS PLAN

2013

1. Employment Conditions

As a Government Owned Corporation covered by federal industrial relations legislation, Ergon Energy will continue to meet its obligations consistent with the guidelines provided by the Queensland Government and the Federal Government’s Fair Work Act 2009.

Ergon Energy employees are employed under the following industrial instruments and identified arrangements as applicable:

The Ergon Energy Union Collective Agreement 2011 (EEUCA 2011). This is the only industrial instrument that is applicable to Ergon Energy Award-enterprise agreement covered employees; and

Total Employment Cost (TEC) or Total Fixed Remuneration (TFR) contracts for employees outside the application of the EEUCA 2011.

As at 1 Jan 2013, there were the following numbers of employees covered by these employment arrangements:

The EEUCA 2011 applies to all employees of Ergon Energy, except those employees paid a salary for the purposes of superannuation which exceeds 115 per cent of salary point 16.5 and those on a TEC or TFR employment contract.

Salary increases for TEC-TFR employees are set each year by the Ergon Energy Board and considers factors such as market data, shareholder expectations and individual performance, etc.

2. Enterprise Bargaining and Productivity Initiatives

The EEUCA 2011 has a nominal expiry date of 1 October 2014. Ergon Energy will progress preparations for bargaining for a replacement agreement, including relevant approvals in accordance with the applicable Government Owned Corporations Wages Policy, as required during 2013.

The EEUCA 2011 provides for a 2.5% per annum base wage increase and a further 1% per annum on-wage productivity funded increase, with the following productivity initiatives being agreed with the parties to the Agreement:

Agreed Productivity Initiative Target Achievement

Inclusion of use of contractors’ provisions within the Agreement to facilitate contracting out of core work required to meet operational requirements within the Ergon Energy Works Program.

Completed

Internal processes for use of contractors in place. Core work contracted to deliver works program requirements.

Utilisation of contractors for high voltage switching and isolation of Single Wire Earth Return (SWER) transformers in rural and remote locations.

Completed Contractors undertaking applicable SWER work as required.

Type Number of Employees

Enterprise Agreement 4,766

TEC and TFR 98


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Agreed Productivity Initiative Target Achievement

Ability of Ergon Energy to implement start and finish on the job arrangements.

Ongoing

Applicable business areas and projects and arrangements being assessed.

The progression of standardised roster arrangement across the Townsville and Rockhampton Operational Control Centres by the conduct of a review to be completed by August 2012.

Ongoing

Finalised roster for the Operational Control Centres developed and implemented.

New Technology and Work Practices. Ongoing Implementation will occur in accordance with program scope and plan.

The implementation of a program of health and wellbeing initiatives for employees to self-manage their own health

Completed

Program of health and wellbeing initiatives programmed and implemented in accordance with program scope and plan.

Ergon Energy will continue to submit quarterly progress reports to Queensland Treasury on the productivity initiatives.

3. Interstate Acquisitions-Operations

There are no interstate acquisitions or operations to report.

4. Redundancy Provisions

Schedule 3 of the EEUCA 2011 contains the Ergon Energy redundancy provisions, which meet the legislative requirements.

In summary, the redundancy provisions provide:

An ex-gratia retrenchment payment of three (3) weeks per year of service, together with a proportionate amount for an incomplete year of service. The minimum and maximum retrenchment payment will be four (4) weeks and seventy five (75) weeks respectively.

An Early Separation Incentive Payment (ESIP) of 13 weeks will be paid where applicable. Approval of ESIP is at the discretion of Ergon Energy. Employees must apply for ESIP within 14 days of notification and their employment must terminate within 14 days of receipt of approval of an ESIP application. Applications for ESIP may be refused or delayed by Ergon Energy if acceptance would be detrimental to its operations.

Annual Leave: Payment for annual leave includes an employee’s accumulated balance as well as the pro-rata balance. Pro-rata annual leave is paid to the date of termination.

Long Service Leave: A long service leave payment of 1.3 weeks for each completed year of service will be made.

Any approved and documented Time Off in Lieu (TOIL) balances will be paid out at the base rate applicable at the time of termination.


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5. Superannuation

Ergon Energy makes superannuation contributions on behalf of eligible employees to Energy Super Fund, which meets the legislative requirements.

All Ergon Energy employees who are employed under the EEUCA 2011 must be members of the Energy Super Fund. Choice of super fund is only available to employees outside the application of the Enterprise Agreement on TEC or TFR contracts.

There are employees in both the Defined Benefit and the Defined Contribution parts of the Energy Super Fund. The Energy Super Defined Benefits section is closed to new employees of Ergon Energy (i.e. all new employees join the Defined Contribution part of the Fund).

As at 1 January 2013, Ergon Energy has the following numbers in each of parts the Energy Super Fund:

Defined Contribution – 3,667 employees; and

Defined Benefit – 1,180 employees

Choice - 17

6. Types of Employment

The following table reflects the categories of employment for Ergon Energy’s total directly employed and total workforce:

Employment Category 30 June 2012

Actual 30 June 2013

Estimate

Permanent Full Time 1 4,354 4,026

Permanent Part Time 162 117

Other Contract 2 96 37

Senior Executive Contract 3 10 10

Apprentices (In House) 4 227 219

Trainees (In House) 5 83 93

Casual Employees 6 130 110

Total Directly Employed Workforce 5,062 4,612

Apprentices Group 0 0

Trainees Group 0 0

Contractor Employees (Trade-Technical) 7 753 667

Contractor Employees (Prof-Admin-Clerical) 8 51 21

Labour Hire (Trade-Technical) 9 44 18

Labour Hire (Prof-Admin-Clerical) 10 228 16

s457 Temporary Visa (excluded from total) 11 3 4

Number of Employees engaged on AWAs with Contractors 0 0

Total Workforce 6,141 5,338

Notes:

All figures are total directly employee numbers, not FTE. Apprentice totals fluctuate throughout the year. The 30 June 2013 estimate was made in March 2013 when the Ergon Energy Employment and Industrial Relations Plan 2013 was prepared (see footnote 8).

1. Permanent Full Time includes Permanent Full Time employees and Sponsored Apprentices (35 Sponsored Apprentices included in this figure).

2. Other Contract employees include Fixed Term Full Time, Fixed Term Part Time and Vacation Students. 3. Senior Executive Contract employees include the Chief Executive and the Executive Leadership Team. 4. Apprentices (In House) include all other apprentices (classified as Internal New at Ergon). 5. Trainees (In House) include all trainees under the scope of the Technical Trainee Program.


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6. Casual employees include all employees who work at Ergon on a casual basis, mainly as Power Station Attendants. 7. Contractor (Trade-Technical) employees include all core tendered contractors provided by the Works and

Contract Management Group, three field classified Professional Services Contractors and one field classified Consultant.

8. Contractor (Professional-Administrative-Clerical) employees include Professional Services Contractors, Project Resources and Consultants with an office based classification.

9. Labour Hire (Trade-Technical) includes external Labour Hire Full Time and Part Time resources with a field classification.

10. Labour Hire (Professional-Administrative-Clerical) includes external Labour Hire Full Time and Part Time resources with an office classification.

11. S457 Temporary Visa employees are already counted in one of the categories that make up the Total Directly Employed Workforce total and are on temporary visa while their permanent residency visas are being processed.

7. Workplace Health & Safety

At Ergon Energy, safety is our number one SPIRIT (Safety, Professionalism, Integrity, Respect, Innovation and Teamwork) value and is at the heart of everything we do. Our vision is to achieve sustained progress towards zero harm and be amongst the top quartile of performers for health and safety amongst our peer group in Australia.

Ergon Energy complies with all relevant health and safety legislation, standards, codes of practice, Australian Standards and industry guidelines.

Ergon Energy was recertified against AS-NZ 4801, AS.NZS 14001 and OHSAS 1800:2007 in October 2012. The external health, safety and environment audit process includes six (6) monthly surveillance audits with a recertification audit every three (3) years.

Certification with the Electrical Safety Office (ESO) is retained each year to conduct business as an electrical entity which requires an annual external audit of our design, construction, operation and maintenance safety management system framework.

8. Consultation

Ergon Energy has undertaken consultation on various aspects of this plan with the Department of Energy and Water Supply, Queensland Treasury and Trade and the Public Service Commission.

Consultation on this plan has also occurred with unions and employees, and any issues raised have been recorded and where appropriate incorporated into the plan or relevant policy, procedure as applicable to the circumstances.

9. Reporting

Ergon Energy will provide reports on performance against this plan to Queensland Treasury and Trade. Progress on achievement of the productivity initiatives in the EEUCA 2011 will be reported quarterly to shareholding Ministers as required by Queensland Treasury and Trade.


45


SPARQ Solutions Pty Ltd Employment and Industrial

Relations Plan 9

Shareholder Information

Employment and Industrial Relations Philosophy and Direction

SPARQ Solutions is a client-focused, cost-effective Information and Communications Technology (ICT) shared service provider to Energex Limited (Energex) and Ergon Energy Corporation Limited (Ergon Energy). SPARQ Solutions works as an integral part of both Ergon Energy and Energex to achieve their business goals by developing, implementing and operating ICT solutions to enable business capability and performance. SPARQ Solutions’ purpose is to provide value to Energex, Ergon Energy and their customers, through the provision of solutions and services for the Electricity Industry.

Jointly owned by Energex and Ergon Energy, the company was established in July 2004 through the amalgamation of the ICT Services of its shareholders. While not a subsidiary in Corporations Law terms due to the joint ownership structure, SPARQ Solutions was declared a subsidiary of Energex and Ergon Energy for the purposes of the Government Owned Corporations Act 1993 by Regulation in March 2006.

As SPARQ Solutions is a subsidiary of Ergon Energy and Energex, the SPARQ Solutions Employment and Industrial Relations Plan (E&IR Plan) forms part of the E&IR Plans of its shareholders. However, as a separate legal entity with its own operational requirements and business drivers, the SPARQ Solutions E&IR Plan stands in its own right, and to the extent of any inconsistency between its E&IR Plan and the E&IR Plans of its shareholders, the SPARQ Solutions E&IR Plan will prevail.

Significant and Emerging Issues

SPARQ Solutions plans to continue to partner with Energex and Ergon Energy to increase their value by providing information technology and telecommunications that meets their needs. It is anticipated that 2013-2014 will include significant industry changes impacting Energex, Ergon Energy and SPARQ Solutions. This plan generally makes provision for the anticipated changes, however, is contingent on those changes being settled and communicated by the Queensland State Government.

There is growing customer concern over increasing electricity prices which have been, in part, driven by expanding electricity network charges. The increase in electricity prices has generated a number of Government reviews of the industry with the implementation of resulting recommendations potentially posing significant challenges for SPARQ Solutions in 2013-14.

SPARQ Solutions will continue to ensure efficiency of ICT expenditure and will consider further progression and deployment of a multi-sourcing strategy.

Implementation of Enterprise Agreement – SPARQ Solutions Union Collective Agreement 2012:

SPARQ Solutions will continue to focus on delivering savings from the enterprise agreement productivity measures.

9 Note: The contents of the SPARQ Solutions Pty Ltd Employment and Industrial Relations Plan 2013 are

accurate as at the time of preparation and final consultation undertaken in March 2013.


46


Directors-Senior Executive Remuneration

SPARQ Solutions Pty Limited: Senior Executive Remuneration as at 1 July 2012:

Name of Incumbent

Position Title

Base Salary

Employer Superannuation

Contributions

Motor Vehicle

Car Park

Other Personal Benefits

Total Fixed Remuneration

Other Non-

Personal Benefits

Performance Payment Made (1)

Peter Effeney

Chief Executive

$354,554 $35,451 0 0 0 $390,005 0 $41,773

Col Hanley Applications

Capability Manager

$217,941 $21,792 0 0 0 $239,733 0 $24,849

Bryce Maskey

Projects Delivery Manager

$222,413 $20,025 0 0 0 $242,438 0 $25,584

Paul Cockburn

Service Delivery Manager

$224,893 $20,249 0 0 0 $245,142 0 $26,571

Jonathan Thompson

CFO $243,643 $24,362 0 0 0 $268,005 0 $29,473

Peter Poncini

Group Manager –

Office of CIO $232,717 $23,269 0 0 0 $255,986 0 $28,116


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SPARQ Solutions Employment and Industrial Relations Plan

Employment Conditions

As a subsidiary of a Government Owned Corporation covered by federal industrial relations legislation, SPARQ Solutions will continue to meet its obligations consistent with the guidelines provided by the Queensland Government and the Federal Government’s Fair Work Act 2009.

SPARQ Solutions employees are employed under the following industrial instruments and identified arrangements as applicable:

The SPARQ Solutions Union Collective Agreement 2012 (SSUCA 2012). This is the only industrial instrument that is applicable to SPARQ Solutions Award-enterprise agreement covered employees; Individual Employment Arrangements (IEA’s) operating within the enterprise agreement parameters. These arrangements provide for market rate salary adjustments and at-risk performance incentives; and Total Employment Cost (TEC) or Total Fixed Remuneration (TFR) contracts for employees outside the application of the Enterprise Agreement.

As at 1 Jan 2013, there were the following numbers of employees covered by these employment arrangements:

Type Number of Employees

Enterprise Agreement 336

IEA 4

TEC and TFR 11

The SSUCA 2012 applies to all employees of SPARQ Solutions, except those employees paid a salary for the purposes of superannuation which exceeds 115 per cent of salary point 16.5 and those on a TEC or TFR employment contract.

Salary increases for TEC-TFR employees are set each year by the SPARQ Solutions Board and considers factors such as market data, shareholder expectations and individual performance, etc.

Enterprise Bargaining and Productivity Initiatives

The SSUCA 2012 has a nominal expiry date of 29 January 2016. SPARQ Solutions will progress preparations for bargaining for a replacement agreement, including relevant approvals in accordance with the applicable Government Owned Corporations Wages Policy, as required during 2015.

The SSUCA 2012 provides a 2.5% per annum base wage increase and a further 1% per annum on-wage productivity funded increase, with the following productivity initiatives being applicable. In addition, an annual 0.5% productivity funded cash payment (on base salary) is due on 30 January each year, with staff having the options to salary sacrifice the payment to superannuation.

Productivity Initiative Target End Date Achievement to Date

Initiative 1:

Support for change - new ways of working

Progressively and ongoing

A number of initiatives are underway as part of the SPARQ Solutions Business Plan 2012-13. These initiatives involve maximising the benefits available to SPARQ Solutions through


48


Productivity Initiative Target End Date Achievement to Date

the introduction of new technology and operating arrangements and include:

Implementation of the new Service Desk Contract and Next Generation Desktop Support arrangements;

Enhancing Project Delivery efficiency and effectiveness.

Initiative 2:

Embedding enhanced process management framework


A revised process management framework was implemented company-wide in September 2012.

All existing processes were reviewed as part of the implementation. Processes were migrated to the new framework as part of the implementation.

Under the revised framework, greater accountability has been provided to process owners and administrators to ensure continuous improvement of processes and workflows as a standard way of operating.

Initiative 3:

Support for organisational Cultural Improvement and Employee Well-being


All current employees have completed Zero Incident Process training (ZIP).

A program of embedding activities was developed and implemented throughout 2012. This will continue in 2013.

This includes monthly company-wide communication of relevant ZIP themes.

Adoption of ZIP principles in managing change.

Active involvement of an employee implementation team in developing initiatives (ZiPIT).

SPARQ Solutions also launched an online Health and Wellbeing Portal in December 2012 which provides employees access to a range of resources to support their ability to self-manage their own health.

Interstate Acquisitions-Operations

There are no interstate acquisitions or operations to report.


49


Redundancy Provisions

Schedule 6 of the SSUCA 2012 contains the SPARQ Solutions redundancy provisions, which meet the legislative requirements.

In summary, the redundancy provisions provide:

An ex-gratia retrenchment payment of three (3) weeks per year of service, together with a proportionate amount for an incomplete year of service. The minimum and maximum retrenchment payment will be three (3) weeks and seventy five (75) weeks respectively.

An Early Separation Incentive Payment (ESIP) of 13 weeks will be paid where applicable. Approval of ESIP is at the discretion of SPARQ Solutions. Employees must apply for ESIP within 14 days of notification and their employment must terminate within 14 days of receipt of approval of an ESIP application. Applications for ESIP may be refused or delayed by SPARQ Solutions if acceptance would be detrimental to its operations.

Annual Leave: Payment for annual leave includes an employee’s accumulated balance as well as the pro-rata balance. Pro-rata annual leave is paid to the date of termination.

Long Service Leave: A long service leave payment of 1.3 weeks for each completed year of service will be made.

Any approved and documented Time Off in Lieu (TOIL) balances will be paid out at the base rate applicable at the time of termination.

Superannuation

In accordance with the relevant Superannuation legislation, all employees can elect to choose a complying superannuation fund other than the default fund (Energy Superannuation Fund).

There are employees in both the Defined Benefit and the Defined Contribution parts of the Energy Super Fund. The Energy Defined Benefits section is closed to new employees of SPARQ Solutions (i.e. all new employees join the Defined Contribution part of the Fund).

As at 1 January 2013, SPARQ Solutions has the following numbers in each of the Superannuation Funds:

Energy Super Defined Contribution – 274 employees

Energy Super Defined Benefit – 64 employees; and

Other – own choice of superannuation fund – 13 employees

Types of Employment

The following table reflects the categories of employment for SPARQ Solutions total directly employed and total workforce:


Actual 30 June 2013

Estimate Permanent Full Time (includes IEA’s) 361 332

Permanent Part Time 4 3

Other Contract (TEC) 7 6

Senior Executive Contract 6 6

Apprentices (In House) - -

Trainees (In House) - -

Casual Employees - -

Total Directly Employed Workforce 378 347


50



Actual 30 June 2013

Estimate

Apprentices Group - -

Trainees Group - -

Contractor Employees (Trade-Technical) - -

Contractor Employees (Prof-Admin-Clerical) 185 135

Labour Hire (Trade-Technical) - -

Labour Hire (Prof-Admin-Clerical) 39 27

s457 Temporary Visa (excluded from total) - -

Total Workforce 602 509

Notes: All figures are total directly employed personnel numbers, not FTE.

Workplace Health & Safety

SPARQ Solutions complies with all relevant health and safety legislation, standards, codes of practice, Australian Standards and industry guidelines.

SPARQ Solutions has a robust Safety Management System and associated processes in place which is certified to AS4801.

SPARQ Solutions was reassessed and received re-accreditation for AS-NZS 4801; 2001 and AS-NZS 14001; 2004 in July 2012. The external health, safety and environment audit process includes six (6) monthly surveillance audits with an accreditation audit every three (3) years.

Consultation

SPARQ Solutions has undertaken consultation on various aspects of this plan with the Department of Energy and Water Supply, Queensland Treasury and Trade and the Public Service Commission.

Consultation on this E&IR Plan has also occurred with unions and employees, and any issues raised have been recorded and where appropriate incorporated into the plan or relevant policy, procedure as applicable to the circumstances.

Reporting

SPARQ Solutions will provide reports on performance against the employment and industrial relations plan to Queensland Treasury and Trade. Progress on achievement of the productivity initiatives in the SSUCA 2012 will be reported quarterly to shareholding Ministers as required by Queensland Treasury and Trade.


51


ATTACHMENT 2: Sponsorship, Advertising, Corporate

Entertainment, Donations and Other Arrangements

Overview

Table 7: Summary of Sponsorship, Advertising, Corporate Entertainment,

Donations and Other Arrangements Budget and Actual Expenditure

Activity10 2011-12 Actual

2012-13 2012-13 Actual

2013-14

Budget Budget

Advertising (And Other Marketing Channels)

3,299,442 3,732,052 3,520,112 3,424,500

Community Partnership Program 1,053,930 539,400 430,227 489,700

Corporate Entertainment 160,327 85,000 62,561 67,000

Other Related Activities 1,590,969 81,400 72,900 85,977

TOTAL 6,360,208 4,437,852 4,085,800 4,067,177

Ergon Energy’s advertising, sponsorship, corporate entertainment, donations and other related expenditures were reviewed in 2012-13 and the budget reduced accordingly. Further reductions have been applied to the 2013-14 budget presented here. In some areas additional budget areas have been included to improve transparency. The budget is based on Ergon Energy continuing to operate with its current accountabilities and structure.

Ergon Energy’s engagement is around achieving the strategic goal of limiting network charges to less than CPI. It is only through customers changing their energy consumption that we will be able to reduce the growth of peak demand and defer network investment, ultimately taking the pressure off electricity prices and helping reduce the CSO.

Apart from these network efficiency objectives, as a combined distributor and retailer, Ergon Energy engages customers in a range of other areas including electrical safety, storm response, managing electricity bills, emergency management, infrastructure planning- projects and network connections. This work assists Ergon Energy to build awareness on issues of community concern such as how to interact safely with Ergon Energy assets and who to contact in an emergency.

Advertising and other Related Activities

Ergon Energy uses its marketing channels to engage with customers and build advocacy. It is an essential tool to build community awareness and prompt the behavioural change required to support demand management, and raise awareness of network issues, including public safety around electricity and preparedness for summer storms. Customer response to these communication activities is regularly tested to assess and improve effectiveness.

10 The budget for Billing and Payments Options has been moved into the Advertising category from the Other

Related Activities category and Corporate Memberships have been moved to Other Related Activities (included in Community Partnerships in 2012-13). The summary table reflects the actual budgets in the previous SCIs, in the detailed table the historical budget has been moved with the estimate-forecast. Additional budgets have also been included. Also, the 2012-13 budget originally included $18,350 for Donations, however this expenditure was discontinued during 2012-13 and actual 2012-13 expenditure was zero. For this reason, the donations category has been removed from the table.


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Community Partnerships

Our community partnership activities allow us to engage directly with communities to build community support, strengthen stakeholder relationships, and facilitate business outcomes. The sponsorship-membership program is focused on local community engagement, energy-related education-activities and sponsorship of other grass roots activities.

Corporate Entertainment & Donations

Ergon Energy’s external stakeholder Corporate Hospitality budget continued to be reduced in line with expectations. As part of the efficiency review the budget for employee Christmas functions is also being reviewed. The PowerAid donations program was discontinued in 2012-13; no other donations are being made.


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2013-14 Detailed Budget

Activity Description - Benefit 2012-13 Budget

($)

2012-13 Actual

($)

2013-14 Budget

($) 2013-14 Quarter 4,5

2013-14

Per Head

Budget

($)

Sep Dec Mar Jun

ADVERTISING (and other marketing activities)

Campaigns over $5,000

Distribution Network Efficiency (was Energy Conservation- Peak Demand)

1,600,000 1,330,267 1,230,000 307,500 307,500 307,500 307,500

Community and high risk industry safety

700,000 1,111,761 900,000 225,000 225,000 225,000 225,000

Billing & Payment Options: 1 500,000 125,527 455,000 113,750 113,750 113,750 113,750

Other expenditure over $5,000

General customer engagement (incl newsletter)

300,000 432,590 440,000 110,000 110,000 110,000 110,000

Contracted agency fees 500,000 456,428 100,000 25,000 25,000 25,000 25,000

Leveraging the Community Partnership program

65,000 38,927 62,000 15,500 15,500 15,500 15,500

Other marketing activities 2 67,052 24,612 237,500 59,375 59,375 59,375 59,375

TOTAL ADVERTISING (1) 3,732,052 3,520,112 3,424,500 856,125 856,125 856,125 856,125

COMMUNITY PARTNERSHIP PROGRAM

Sponsorship of individual entities over $5,000

Queensland Energy Museum - preservation of the history of the electricity industry

77,000 77,000 47,300 47,300 0 0 0

LGAQ and LGMA - local government engagement

50,000 44,570 40,000 0 10,000 15,000 15,000


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($)

2012-13 Actual

($)

2013-14 Budget

($) 2013-14 Quarter 4,5

2013-14

Per Head

Budget

($)

Sep Dec Mar Jun

QUT Business Leaders Forum - business stakeholder engagement

25,000 25,000 25,000 0 25,000 0 0

Carnival of Flowers - regional stakeholder engagement - energy efficiency messages

50,000 50,000 50,000 50,000 0 0 0

Queensland Music Festival - Indigenous engagement

20,000 0 20,000 0 0 20,000 0

General community sponsorship program - funds over $5,000 not yet allocated to entities. 3

135,000 98,810 125,000 15,000 50,000 10,000 50,000

TOTAL OVER $5,000

357,000 295,380 307,300 112,300 85,000 45,000 65,000

Sponsorship of entities under $5,000

Tactical local community sponsorships 182,400 134,847 182,400 45,600 45,600 45,600 45,600

TOTAL COMMUNITY PARTNERSHIP PROGRAM (2) 539,400 430,227 489,700 157,900 130,600 90,600 110,600

CORPORATE ENTERTAINMENT

Event over $5,000

Staff Christmas Function 4 70,000 62,561 65,000 0 50,000 15,000 0 28

Corporate Hospitality - Tickets5 15,000 0 2,000 1,000 0 1,000 0

TOTAL CORPORATE ENTERTAINMENT (3) 85,000 62,561 67,000 1,000 50,000 16,000 0


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($)

2012-13 Actual

($)

2013-14 Budget

($) 2013-14 Quarter 4,5

2013-14

Per Head

Budget

($)

Sep Dec Mar Jun

OTHER RELATED ACTIVITIES

Corporate memberships - interface with key stakeholders on regional development issues 1

Townsville Enterprise 33,000 30,900 33,000 0 33,000 0 0

Capricorn Enterprise 20,000 20,000 20,000 20,000 0 0 0

Mount Isa to Townsville Economic Development Zone Inc6

0 0 10,000 10,000 0 0 0

Tourism Tropical North Queensland 8,400 0 2,977 2,977 0 0 0

Mackay Whitsunday Regional Economic Development Corporation

20,000 22,000 20,000 0 20,000 0 0

TOTAL OTHER RELATED ACTIVITIES (4) 81,400 72,900 85,977 32,977 53,000 0 0

TOTAL (1)+(2)+(3)+(4) 7 4,437,852 4,085,800 4,067,177 1,048,002 1,089,725 962,725 966,725

Notes: This report covers campaign advertising and marketing activity, not operational advertising (recruitment, tenders, etc) or web site development and maintenance. 1. The budget for Billing and Payments Options has been moved into the Advertising category from the Other Related Activities category and Corporate Memberships have been moved to Other Related Activities (included in Community Partnerships in 2012-13). The summary table reflects the actual budgets in the previous SCIs, in the detailed table the historical budget has been moved with the estimate-forecast. Additional budgets have also been included in this budget summary for 2013-14 following an internal review to improve transparency. 2. Other marketing activities includes; ROAMES trade shows etc ($50,000 previously budgeted in Community Partnerships); advertising activities charged by EECL to Nexium Telecommunications ($30,000); Enterprise Development market development for workshops ($20,000); all marketing activities for the energy savings pilot powersavvy ($57,500: note last year included advertising only not educational publications); and Energy Sense Communities-Alternative Energy Solutions ($ 80,000). 3. Includes the Community Fund and our educational program (in 2012-13 this was a partnership agreement utilising the NQ Cowboy's community-school engagement program to deliver energy conservation messages. This is currently being reviewed). 4. Christmas functions are organised by the regional employee social clubs who receive a maximum reimbursement of $28 per head. This budget covers all regions. 5. No Corporate Hospitality expenditure has been recorded in 2012-13. This budget element has been reduced to $2,000 for 2013-14 in line with the expectations. 6. Membership not previously been shown in SCI in 2012-13. 7. The 2012-13 budget of $18,350 for Donations has been removed from this table as this expenditure has been discontinued.

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