1. Financial performance

Principal activities

The principal activities of AGL at reporting date consisted of the operation of energy businesses, and investments, including electricity generation, gas storage and the sale of electricity and gas to residential, business and wholesale customers. The acquisition of Southern Phone Company in December 2019 expanded AGL’s activities to include the retailing of broadband and mobile services.

1.1. Group results summary

1.1.1. Reconciliation of Statutory Profit to Underlying Profit

1.1.1.1. Profit after tax

Statutory Profit after tax was $1,015 million, up $110 million compared with the prior year. This included two items excluded from Underlying Profit:

• A movement in the fair value of financial instruments of $216 million compared with $(139) million in the prior year. This net gain reflected a positive fair value movement in AGL’s net sold electricity derivative contracts as a result of lower forward electricity prices, which was partly offset by a negative fair value movement in net purchased oil derivative contracts as a result of lower forward oil prices. See section 1.1.4 for more detail.
• Significant items of $(17) million from the partial impairment of AGL’s stake in the Powering Australian Renewables Fund and costs associated with the acquisition of Perth Energy.

Underlying Profit after tax was $816 million, down 21.5% from the prior year. A description of the factors driving Underlying Profit is included in section 1.1.2 .

EPS calculations have been based upon a weighted average number of ordinary shares of 640,653,780 (30 June 2019: 655,825,043). The weighted average number of ordinary shares was 15,171,263 lower than the prior year due to the cancellation of 32,686,947 shares under the share buy back program which increased the Statutory and Underlying EPS by 4 cents and 3 cents respectively.

1.1.1.2. Earnings Before Interest and Tax (EBIT)

Effective 1 July 2020, AGL formed the Integrated Energy operating segment. Integrated Energy reflects the consolidation of the previous Wholesale Markets and Group Operations operating segments, adjusted for any intra-segment transactions. For the purposes of the year ended 30 June 2020, Wholesale Markets and Group Operations are reported separately.

Revised structure from 1 July 2020:

1.1.2. Group financial performance

1.1.2.1. Year-on-year movement in revenue ($m)

Total revenue was $12,160 million, down 8.2%, driven by lower electricity generation revenue and gas sales volumes. Lower electricity generation revenue was driven by the major outage of Unit 2 at the AGL Loy Yang power station from May 2019 until January 2020, and lower average wholesale electricity prices compared with the prior year. Gas sales volumes were impacted by lower volumes sold to the existing Wholesale customer base and the loss of Large Business customers resulting from the challenges of sourcing gas in a tight market as AGL's legacy lower cost gas supply contracts roll off. This was partly offset by increased revenue in Customer Markets from growth in customer service numbers and the acquisitions of Perth Energy (in September 2019) and Southern Phone Company (in December 2019).

1.1.2.2. Year-on-year movement in gross margin ($m)

Total gross margin was $3,677 million, down 4.1%. The decrease was largely attributable to the Wholesale Markets operating segment and reflected the revenue impact noted above as well as lower prices for large-scale generation certificates (LGC) relating to renewable energy production. Refer to section 1.4 for further analysis on the movement in gross margin for each operating segment.

1.1.2.3. Operating costs

Total operating costs (excluding depreciation and amortisation) were $(1,607) million, up 3.8%. There were ongoing savings across AGL from recent digital transformation initiatives and other efficiency programs of a combined $57 million, in addition to the non-recurrence of programs to forgive $33 million of additional customer debt in the prior year. These savings were not sufficient to offset increased costs and those associated with AGL’s response to COVID-19, including increased allowance for expected credit loss as a result of the impact of some customers’ ability to pay their bills and other customer support initiatives ($20 million) and additional costs to ensure employees and contractors were able to work safely and securely at AGL generation sites to ensure ongoing supply of power during the pandemic restrictions ($18 million). Other cost increases related to the inclusion of acquired businesses ($26 million), increased investment in maintaining plant availability ($15 million), higher insurance premiums mostly related to business interruption insurance policies covering AGL’s coal-fired power plants and increased regulatory costs ($11 million) and investment in the Decentralised Energy business (batteries, electric vehicles and other small-scale energy generation, storage and orchestration services) ($8 million).

As a result of internal restructuring during the year, prior year costs were reallocated, including $(22) million of costs associated with the Property, Procurement and Security function and $(9) million of costs associated with the Health, Safety and Environment function transferred from Group Operations to Centrally Managed Expenses. Additionally, $(9) million of costs associated with AGL's digital development capabilities transferred from Customer Markets to Centrally Managed Expenses.

Refer to section 1.4 for further analysis on the movement in operating costs for each operating segment.

1.1.2.4. Depreciation and amortisation (D&A)

Depreciation and amortisation of $(753) million was up 20.5%. Excluding the impact of depreciation and amortisation transfers to Centrally Managed Expenses following the internal reorganisation noted above, this occurred principally in Group Operations as a result of: a higher asset base at AGL Macquarie and AGL Loy Yang from increased reliability focused capital expenditure; a shorter depreciation schedule at Liddell Power Station at AGL Macquarie given its pending closure in FY23; and the completion of the $295 million Barker Inlet Power Station project during the year. Increases in Customer Markets and Centrally Managed Expenses (excluding the impact of transfers noted above) reflected the recent completion of the Customer Experience Transformation and enterprise resource planning system upgrades respectively.

1.1.2.5. Year-on-year movement in Underlying Profit after tax ($m)

Underlying Profit after tax was $816 million, down 21.5% on the prior year. The principal drivers of the decrease in margin were from the Unit 2 outage at AGL Loy Yang, reduction in gas sales volumes, lower wholesale electricity and LGC prices, and the higher depreciation and amortisation and increases in operating costs noted above. These impacts were partially offset by a 24.6% reduction in Underlying tax expense to $322 million, primarily reflecting the decrease in profit, and a 7.3% reduction in net finance costs to $179 million, down due to lower facility interest rates. The underlying effective tax rate was 28.3%, a decrease of 0.8 ppts compared with the prior year.

1.1.3. Significant items

1.1.3.1. Acquisitions and disposals

2020

On 2 September 2019, AGL completed the purchase of 100% of the outstanding share capital of Perth Energy Holdings Pty Ltd. Acquisition related transaction costs of $7 million post-tax were recognised as a Significant Item in the year.

2019

On 11 September 2018, AGL completed the sale of a portfolio of small generation and compressed natural gas refuelling assets, known as AGL’s National Assets portfolio, to Sustainable Energy Infrastructure, a consortium led by Whitehelm Capital. A post-tax profit of $37 million was recognised in the year.

In December 2018, AGL disposed of the option to purchase the Yandin wind farm development rights in Western Australia. A post-tax profit of $5 million was recognised as a Significant Item in the year.

1.1.3.2. Asset impairments

2020

During the year, AGL partially impaired the carrying value of its investments interest in the Powering Australian Renewables Fund, reflecting revised market pricing and generation output assumptions for operations sites. A post-tax impairment loss of $10 million was recognised as a Significant Item in the year.

2019

On 11 September 2018, AGL announced the decision to exit the residential solar installation operations, rendering many of the residential solar assets obsolete. A post-tax loss of $38 million was recognised as a Significant Item in the year to account for the write down of goodwill, systems related assets, inventory and other business closure costs.

1.1.4. Changes in fair value of financial instruments

1.1.4.1. AGL's approach to hedging

AGL’s approach to managing energy price risks, through physical ownership of energy generation, contracting for energy supply and financial hedging, reflects the need to provide pricing certainty to customers and limit exposure to adverse wholesale market outcomes. AGL generates electricity or has contracted gas supply in excess of its customers’ demand in some states. In other states, AGL has sources of supply less than its customers’ demand.

AGL uses certain financial instruments (derivatives) to manage these energy price risks and to manage its exposure to interest and foreign exchange rates arising in the normal course of business, provided the overall AGL risk appetite is not exceeded. The majority of these financial instruments exchange a fixed price for a floating market-based price of a given commodity, interest rate, currency or a quoted asset, with the net differential being settled with the counterparty. AGL is exposed to price volatility on the sale and purchase of energy-related commodities in the normal course of business, and therefore enters into contracts that minimise the price risk to AGL on both sold and purchased forecast exposures.

AGL has in place a governance framework that establishes the policy guidelines under which energy hedging activities are conducted. Key components of that policy include segregation of duties, independent risk oversight, earnings-at-risk limits, compliance management and regular reporting to the Board. The risk policy represents the Board’s and Senior Management’s commitment to an effective risk management function to ensure appropriate management and oversight of AGL’s risks related to wholesale markets energy risk. The policy allows for commercial optimisation of the portfolio provided that AGL adheres to overall earnings-at-risk limits that reflects its risk appetite.

1.1.4.2. Energy price risk

Certain purchased contracts traded prior to 1 July 2019 are designated as hedge relationships when they can be matched to forecast transactions with sufficient probability of the forecast transaction occurring. Derivative instruments assigned to an effective hedge relationship have movements in fair value deferred to an equity hedge reserve until the transactions to which those instruments are matched occur. Derivative instruments not assigned to an effective hedge relationship have movements in fair value recognised in profit or loss.

AGL’s energy-related derivatives assigned to hedge relationships are purchased derivative contracts, where AGL pays a fixed price in exchange for a floating price received from the counterparty. The energy-related derivatives recognised in profit or loss are net-sold positions, where AGL receives a fixed price from a counterparty in exchange for a floating price paid to the counterparty.

AGL is required to make margin payments in respect of futures contracts traded through the Australian Securities Exchange (ASX). Initial margin call payments are made at the time contracts are entered in order to manage intra-day credit exposure. The quantum of initial margin depends on the volume traded, the expected market volatility as well as forward electricity prices at the time. The initial margin call can move subsequently as forward prices move. AGL also receives or makes payments known as variation margin calls, which cover mark to market movements of AGL’s open futures position. These typically reverse through future earnings as contract positions roll off.

1.1.4.3. Treasury related risk

AGL’s treasury related risk primarily relates to interest and foreign currency rate fluctuations. Contracts to minimise the exposure to market-based fluctuations are executed pursuant to AGL’s treasury risk management policy. These contracts primarily result in fixed interest and foreign currency rates. These contracts are designated in hedge relationships when they can be matched to forecast transactions with sufficient probability of the forecast transaction occurring.

In addition to the above, AGL is counterparty to cross-currency interest rate swap arrangements to convert its fixed interest rate US dollar private placement borrowing instruments to floating interest rate Australian dollar equivalent borrowing instruments. The cross-currency interest rate swap arrangements are designated as fair value and cash flow hedge relationships.

1.1.4.4. Movement in fair value

The initial fair value of a derivative is the consideration paid or received (the premium). Fair value movements in any given year are a function of changes to underlying indices, market prices or currencies and the roll-off of realised contractual volumes or amounts. A reconciliation of the movements in financial instruments carried at fair value, for the year ended 30 June 2020 is presented in the following table:

The movement in net derivative assets in the year of $367 million is summarised in the table below:

The fair value movement driving the change in the net derivative assets position reflected in unrealised fair value movements is as follows:

• An increase in the fair value of energy-related derivatives of $344 million was recognised in profit or loss (excluded from Underlying Profit). This net gain reflected a positive fair value movement in AGL’s net sold electricity derivative contracts as a result of lower forward electricity prices, which is partly offset by a negative fair value movement in net purchased oil derivative contracts as a result of lower forward oil prices.
• A decrease in the fair value of purchased energy-related derivatives designated as a hedge relationship of $(58) million, which was recognised in the equity hedge reserve. This decrease primarily reflected lower electricity market prices.
• Currency related fair value gain of $110 million recognised in borrowings. This related primarily to the decrease of the AUD forward interest rate curve during the year and the weakening of the AUD/USD foreign exchange rate.

1.2. Cash flow

1.2.1. Reconciliation of Underlying EBITDA to cash flow

1. ¹ Movement in cash and cash equivalents in the Statement of Financial Position is $26 million, which includes $1 million related to the effect of exchange rate changes on the balance of cash held in foreign currencies not included in the above cash flow reconciliation.

Operating cash flow before interest and tax was $2,520 million, up $507 million. The rate of conversion of EBITDA to cash flow was 122%, up from 88% in the prior year. Adjusting for margin calls, the cash conversion rate was 99%, up from 96% in the prior year.

The principal reason for stronger cash flow was a positive working capital movement, compared with a negative cash flow impact from working capital in the prior year. Total working capital movements were $438 million, compared with $(248) million in the prior year. Components of working capital movement were:

• Receivables cash flow of $60 million reflected a reduction in receivables due to lower average bills following the introduction of regulated default offers in each state and customers switching to lower-priced products. The prior year receivables cash flow of $103 million reflected a higher opening balance as well as one-off debt forgiveness actions.
• Payables cash flow of $(156) million reflected lower electricity pool prices and timing of contract positions combined with lower coal payables due to reduced coal deliveries. The prior year trade creditors cash flow of $(21) million reflected lower consumer gas and electricity volumes in the year reducing network creditors partly offset by higher coal payables due to increased deliveries in June.
• Inventory cash flow of $(14) million reflected an increase in spare parts inventory partly offset by a lower coal stockpile at AGL Macquarie following AGL's focus on removing bottlenecks from the coal supply chain. The prior year inventory movement of $(74) million reflected an increase in the AGL Macquarie coal stockpile.
• Margin call cash flow of $471 million reflected a net cash inflow of variation margin calls due to a decrease in the electricity forward curve during FY20. This contrasted to the prior year cash flow of $(187) million where there was a net cash outflow on open positions due to higher wholesale electricity forward prices at that time.
• Green assets and liabilities cash flow of $47 million reflected an increased LGC scheme compliance percentage as well as the impact of certificates purchased in the prior year and surrendered in FY20. The prior year green assets and liabilities cash flow of $(67) million reflected a lower compliance cost for the LGC scheme as well as the purchase of certificates for future surrender obligations.

Tax cash flow of $(233) million was consistent with prior year.

Investing cash flow of $(879) million reflected capital expenditure and the Perth Energy and Southern Phone Company acquisitions. The prior year Investing cash flow of $(904) million reflected higher capital expenditure, partly offset by the sale of the National Assets portfolio.

Financing cash flow of $(1,252) million included dividends of $(719) million, $(620) million share buy-back and a net borrowings drawdown of $94 million. The prior year Financing cash flow of $(1,043) million included dividends of $(774) million and a net borrowing repayment of $(264) million including the redemption of $650 million of Subordinated Notes.

1.2.2. Capital expenditure

1.2.2.1. Summary of capital expenditure split between growth and sustaining

Total capital expenditure was $729 million, a decrease of $210 million compared with the prior year:

• Sustaining capital expenditure was $536 million, a decrease of $15 million. This comprised $355 million of expenditure on AGL’s thermal plants, down $27 million, driven by the deferral of outage work at both AGL Macquarie and AGL Torrens due to COVID-19 related personnel restrictions on site. Other sustaining capital expenditure was $181 million, up $12 million largely due to the increase in regulatory programs and continued investment in Customer Market systems.
• Growth capital expenditure was $193 million, a decrease of $195 million on the prior year. This decrease reflected the non-recurrence from the prior year of the major Customer Experience Transformation and enterprise resource planning systems upgrades and the majority of the construction of the Barker Inlet Power Station. FY20 expenditure included the $62 million final growth spend on Barker Inlet, a $30 million capacity upgrade to the Bayswater Power Station at AGL Macquarie and $19 million of further upgrades to AGL's enterprise resource planning systems.

1.3. Review of financial position

1.3.1. Summary Statement of Financial Position

At 30 June 2020 AGL’s total assets were $14,710 million, a decrease from $14,821 million at 30 June 2019, primarily due to the decrease in the futures deposits and margin calls compared with the prior year Changes in fair value of financial instruments , which is reflected in other current assets.

Total liabilities at 30 June 2020 were $6,635 million, up from $6,383 million at 30 June 2019, primarily reflecting the increase in borrowings to fund the share buy-back.

Total equity at 30 June 2020 was $8,075 million, down from $8,438 million, reflecting the reduction in issued capital due to the share buy-back. AGL’s return on equity, calculated on a rolling 12-month basis was 10.0%, down from 30 June 2019.

1.3.2. Net debt reconciliation

Net debt at 30 June 2020 was $2,723 million, up from $2,600 million at 30 June 2019 due to increased draw downs to fund the share buy back program which were mostly offset by strong operating cash flow.

AGL’s gearing (measured as the ratio of net debt to net debt plus adjusted equity) at 30 June 2020 was 25.0% compared with 23.5% at 30 June 2019.

AGL maintained its credit rating of Baa2 throughout the year as provided by Moody’s Investors Service. Key metrics consistent with this credit rating at 30 June 2020:

• Interest cover: 8.9 times
• Funds from operations to net debt: 38.0%

AGL’s funds from operations has been calculated with a similar methodology to Moody’s whereby the movement in all current and non-current tax assets and liabilities is treated as working capital.

1.4. Review of operations

AGL manages its business in four key operating segments: Customer Markets, Wholesale Markets, Group Operations and Investments. Further detail on the activities of each operating segment is provided below.

In accordance with Australian Accounting Standard AASB 8 Operating Segments, AGL reports segment information on the same basis as its internal management structure. As a result, the Customer Markets and Wholesale Markets operating segments report the majority of the revenue and margin from AGL’s activities, while the Group Operations operating segment reports the majority of the expenses.

Effective 1 July 2020, AGL formed the Integrated Energy operating segment. Integrated Energy reflects the consolidation of the previous Wholesale Markets and Group Operations operating segments, adjusted for any intra-segment transactions. For the purposes of the year ended 30 June 2020, Wholesale Markets and Group Operations are reported separately.

1.4.1. Customer Markets

Customer Markets comprises the Consumer and Large Business customer portfolios responsible for the retailing of electricity, gas, solar and energy efficiency products and services to residential, small and large business customers, and the retailing of telecommunications. Customer Markets sources its energy from Wholesale Markets at a transfer price based on methodologies that reflect the prevailing wholesale market conditions and other energy costs in each state. Customer Markets also includes sales, marketing, brand, and AGL's customer contact and call centre operations.

1.4.1.1. Customer Markets Underlying EBIT

Customer Markets Underlying EBIT was $186 million, down 4.1%, due to lower consumer gross margin across both fuels as a result of customers switching to lower-priced products despite higher volumes driven by customer growth, and higher depreciation and amortisation due to the investment in the Customer Experience Transformation program in prior years. The impact of COVID-19 was reflected in increased operating costs due to an allowance for expected credit loss associated with potential impacts of COVID-19 on customers' ability to pay their energy bills, a significant decrease in electricity demand in the Large Business customer and small business portfolios, and an increase in demand from residential customers. This was partly offset by lower operating costs due to the non-recurrence of one-off debt forgiveness actions in the prior year, a decrease in call centre activity related to customers seeking to switch between retailers and higher digital adoption, lower marketing costs and benefits from the Customer Experience Transformation program.

• Consumer Electricity gross margin was $500 million, down 1.0%, due to customers switching to lower-priced products and the introduction of regulated default market offers in each state. Consumer electricity volumes increased by 2.0%, driven by growth in the average number of electricity services provided to customers.
• Consumer Gas gross margin was $219 million, down 11.0%, driven by customers switching to lower-priced products and the introduction of automatic discounts for all consumer services that have been on standing offers (non-discounted contracts on regulated terms) for more than one year (Gas Safety Net). This was partly offset by higher volumes, up 1.6%, due to an increase in the average number of gas services provided to customers.
• Large Business Electricity gross margin was $36 million, up 5.9% due to higher gross margin rates, slightly offset by the decrease in volumes due to the impact of COVID-19 on Large Business demand in the current year excluding Perth Energy.
• Large Business Gas gross margin was $12 million, down 20.0%, as volumes declined 3.7% due to the loss of customers.
• Fees, charges and other margin was $20 million, down 25.9%, due to lower margin from intermediary businesses and a reduction in late payment fees for customers not paying on time.
• Southern Phone Company gross margin since acquisition includes retailing of telecommunications, specifically mobile, broadband and voice services.
• Perth Energy gross margin since acquisition includes generation and retailing of electricity and gas to small and large business customers within Western Australia.
• Depreciation and amortisation was $(132) million, up 30.7%, due to the investment in the Customer Experience Transformation program over the period FY17 to FY19.

1.4.1.2. Customer Markets operating costs

Customer Markets operating costs (excluding depreciation and amortisation) were $(500) million, down $32 million, reflecting the non-recurrence of one-off debt forgiveness actions in the prior year, reduced costs associated with a decrease in market activity and the benefits of the Customer Experience Transformation program. This was partly offset by an increase in allowance for expected credit loss as a result of the impact of COVID-19 on some customers’ ability to pay their bills, the COVID-19 payment support program, and the introduction of operating costs associated with Southern Phone and Perth Energy. In addition, the prior year included costs of $(9) million associated with AGL’s digital development team, which is now reported within Centrally Managed Expenses following transfer to the Future Business & Technology function.

• Labour and contractor services costs were $(185) million, up 3.9% due to the inclusion of Perth Energy and Southern Phone and increased regulatory requirements, partly offset by increased customer digital adoption and a decrease in market activity, which resulted in a decline in call volumes. Excluding the impact of acquired businesses, labour and contractor services were $(174) million, down 2.2%.
• Allowance for expected credit loss was $(119) million, down 0.8% driven by the non-recurrence of one-off debt forgiveness actions in the prior year, offset by allowance for expected credit loss increases to reflect heightened repayment risk relating to COVID-19 ($20 million), costs associated with AGL's debt relief provided to customers through the COVID-19 payment support program and bushfire debt relief program, and increased regulatory requirements relating to hardship in the current year.
• Campaigns and advertising costs were $(103) million, down 24.3%, due to reduced market activity and cost reductions achieved through efficiencies from the Customer Experience Transformation program. Churn declined 3.3 ppts from the prior year as lower pricing and simplified offers reduced the amount of retailer switching in the market.
• Other expenditure was $(93) million, down 5.1%, driven by increased digital billing and lower payment channel costs.

1.4.1.3. Consumer energy profitability and operating efficiency

Average consumer energy services increased year-on-year due to targeted campaign activity, lower churn and the growth of customers in Victoria, New South Wales and Western Australia.

AGL churn decreased 3.3 ppts to 14.3% from 17.6% reported at same time last year, and Rest of Market churn decreased 4.5 ppts to 19.4% from 23.9% reported at same time last year. Overall market churn declined across all states following a decrease in the number of customers switching retailers due to lower pricing as a result of the regulatory environment. The gap between AGL and the rest of the market was 5.1 ppts, down from 6.3 ppts as at 30 June 2019.

Acquisitions and retentions decreased to 1.441 million, down 21.3%, primarily driven by lower retention volumes with less existing customers switching compared with the prior year.

EBIT per customer service was $47, down 9.6%, largely due to increased Consumer Gas customers switching to lower priced products in the current year and the introduction of regulated default offers for electricity customers in each State.

Cost to Serve per service includes the consumer operating costs related to serving existing customers divided by the average number of customer services during the year. Cost to Serve per service was $(96), down 1.0%, largely due to the non-recurrence of one-off debt forgiveness actions in the prior year, with the efficiency improvements this year offset by the increase in the allowance for expected credit loss to reflect the heightened delinquency risk relating to COVID-19, the COVID-19 support program and higher depreciation and amortisation costs.

Cost to Grow per service includes the consumer operating costs related to acquiring and retaining customers divided by the average number of customer services acquired and retained during the year. Cost to Grow per service was $(128), up 13.3% largely due to lower retention volumes driven by reduced product switching compared with the prior year, partly offset by lower campaign and advertising spend.

1.4.1.4. Customer numbers and churn

The following table provides a breakdown of customer numbers by state.

Total energy service numbers increased 2.1% to 3.786 million, from 3.708 million reported at 30 June 2019. Consumer electricity customer service numbers have increased as a result of growth in Victoria and New South Wales. Consumer gas customer service numbers have increased due to growth in Victoria and Western Australia. Large Business customer services movement includes the addition of 2,191 Perth Energy services. Targeted campaign activity coupled with a decline in churn has contributed to the growth in customer numbers. Total broadband and phone services of 167,000 were newly acquired with the purchase of Southern Phone Company in December 2019.

1.4.2. Wholesale Markets

Wholesale Markets comprises Wholesale Electricity, Wholesale Gas and Eco Markets and is responsible for managing the price risk associated with procuring electricity and gas for AGL's customers and for managing AGL's obligations in relation to renewable energy schemes. Wholesale Markets also controls the dispatch of AGL's owned and contracted generation assets and associated portfolio of energy hedging products. Since FY19, AGL’s Decentralised Energy business has been a part of Wholesale Markets, and is responsible for the management of the Residential Battery Program and Business Customer Demand Response products, along with other growth initiatives in AGL’s orchestration pathway.

• Wholesale Electricity reflects the procurement of key fuel inputs and hedging of AGL's wholesale electricity requirements, for commercial management of the generation portfolio and for wholesale pricing to support AGL's consumer and business customer bases.
• Wholesale Gas reflects the sourcing and management of AGL's gas supply and transportation portfolio. Wholesale Gas supplies other retailers, internal and third-party gas-fired generators, and other gas customers. Wholesale Gas is also responsible for the management of the price exposures related to AGL's oil-linked wholesale gas contracts.
• Eco Markets reflects the management of AGL's liabilities relating to both voluntary and mandatory renewable and energy efficiency schemes, the largest being the Large-scale Renewable Energy Target (LRET) and the Small-scale Renewable Energy Scheme (SRES).

1.4.2.1. Wholesale Markets Underlying EBIT

Wholesale Markets Underlying EBIT was $2,613 million, down 5.2%, largely due to the impact of the major outage of Unit 2 at AGL Loy Yang, the reduction in gas sales volumes and lower wholesale prices for electricity and LGCs. This was partly offset by lower coal and gas purchase costs.

• Wholesale Electricity gross margin was $2,211 million, down 1.3%, due to reduced generation at AGL Loy Yang caused by the Unit 2 outage and lower electricity prices. This was partly offset by increased generation from AGL Macquarie, increasing output from the new Coopers Gap and Silverton wind farms, lower wholesale electricity purchase costs, lower unit fuel costs for coal and gas, and the performance of wholesale electricity derivatives during the second half of the financial year. The reduction in coal costs was due to increased deliveries of legacy coal contracts following improvements in delivery logistics and stockpile handling at AGL Macquarie. The gas cost reduction reflected lower generation volumes and a lower unit cost of gas (see below for a detailed explanation of the unit cost decrease).
• Wholesale Gas gross margin was $421 million, down 8.1%, driven by lower customer sales volumes. Total volume sold was 11.6 PJ lower than the prior year, driven by lower volumes on the existing Wholesale customer base and the loss of Large Business Customers resulting from the challenges of sourcing gas in a tight market as AGL's legacy lower cost gas supply contracts roll off, and lower generation volumes. A lower unit cost of gas reflected supply mix benefits, with the reduction in total gas volumes required resulting in a higher proportion of lower priced legacy contracts being used compared with the prior year. This was partly offset by higher haulage and storage costs due to an increase in storage capacity.
• Eco Markets gross margin was $42 million, down 60.4%, largely due to lower LGC market prices resulting in lower transfer price revenue. This was partly offset by lower prices for on-market purchases, increased generation from Coopers Gap and Silverton wind farms and a lower allocation of PPA costs as a result of lower LGC prices, relative to electricity prices.
• Operating costs (excluding depreciation and amortisation) were $(44) million, up 69.2%, largely driven by an increase in labour and other costs associated with the investment in Decentralised Energy, in which AGL is investing to support increased customer demand for products and services such as residential batteries and electric vehicles.

Refer also to the Portfolio Review at section 1.5 for additional analysis of AGL’s electricity and gas portfolios.

1.4.3. Group Operations

Group Operations comprises AGL’s power generation portfolio and other key sites and operating facilities across the Thermal, Renewables, Natural Gas, and Other business units.

• Thermal primarily comprises: AGL Macquarie (4,665 MW), consisting of the Bayswater and Liddell black coal power stations in New South Wales; AGL Loy Yang (2,210 MW), a brown coal mine and power station in Victoria; and AGL Torrens (1,280 MW), a gas power station in South Australia. The Barker Inlet Power Station (210 MW) was operationally completed on 28 January 2020. Kwinana Swift (120 MW), a dual fuel peaking power station, was acquired as part of the Perth Energy acquisition on 2 September 2019.
• Renewables primarily comprises: 786 MW of hydroelectric power stations in Victoria and New South Wales and the operation of 1,581 MW of wind power generation in South Australia, Victoria, New South Wales, and Queensland, and 155 MW of solar power in New South Wales.
• Natural Gas includes the Newcastle Gas Storage Facility in New South Wales, the Silver Springs underground gas storage facility in Queensland, the natural gas production assets at Camden in New South Wales and the North Queensland gas assets, including the Moranbah Gas Project. 

• Other operations primarily consist of Development and Construction, and technical and business support functions.

1.4.3.1. Group Operations Underlying EBIT

The following tables provide a breakdown of the contributors to Underlying EBITDA and Underlying EBIT:

Group Operations Underlying EBIT was $(1,087) million, down 4.9%, driven by increased labour costs due to Enterprise Agreement wage escalations and COVID-19 reducing the amount of leave taken and increasing the amount of overtime required. Additionally there was the non-recurrence of Liddell insurance proceeds received in prior year, COVID-19 response costs to ensure employees were able to safely work on-site, increased costs to maintain plant availability and higher depreciation. The total COVID-19 related cost increase was $18 million. This was partly offset by the transfer of the Property, Procurement and Security, and Health, Safety and Environment functions to Centrally Managed Expenses in the current year ($31 million operating costs excluding depreciation and amortisation in the prior year) and higher revenue and lower costs in Natural Gas.

• Thermal Underlying EBIT was $(914) million, down 14.4%, driven by lower insurance proceeds compared to the prior year and an increase in depreciation predominantly due to a higher asset base at AGL Macquarie and AGL Loy Yang from increased reliability focused capital expenditure. The increased spend at AGL Macquarie is relative to a short depreciation schedule at Liddell Power Station given its committed closure. Additionally, costs were incurred during the current year in response to the COVID-19 pandemic to ensure employees were able to safely work onsite, as well as to maintain plant availability across the thermal fleet, particularly to support the AGL Loy Yang Unit 2 outage.
• Renewables Underlying EBIT was $(102) million, down 5.2%, primarily due to the settlement of Macarthur wind farm claims.
• Natural Gas Underlying EBIT was $(29) million, up 50.0%, primarily due to the decrease in field development costs relating to the Moranbah Gas Project joint venture and increased revenue from gas sales.
• Other operations Underlying EBIT was $(42) million, up 48.8% reflecting the transfer of the Property, Procurement and Security, and Health, Safety and Environment functions to Centrally Managed Expenses in the year. This was partly offset by the reduction in margin from the National Assets business (divested in September 2018).

1.4.3.2. Group Operations operating costs

Group Operations operating costs (excluding depreciation and amortisation) of $(721) million decreased by $5 million compared to the prior year:

• Labour costs were $(350) million, up 6.1%. Excluding the transfer of $15 million in costs associated with the Property, Procurement and Security, and Health, Safety and Environment functions to Centrally Managed Expenses in the current year, labour costs were up 11.1%, or $35 million. This was driven by Enterprise Agreement wage escalations, COVID-19 reducing the amount of leave taken and increasing the amount of overtime required and increased head count of specialised operators at Bayswater to maintain plant availability.
• Contractors and materials costs were $(258) million, down 0.4%, driven by the transfer of the Property, Procurement and Security, and Health, Safety and Environment functions to Centrally Managed Expenses, partly offset by higher costs to maintain plant availability across the thermal fleet, particularly to support the AGL Loy Yang Unit 2 outage.
• Other operating costs were $(113) million, down 17.5%, driven by a decrease in field development costs relating to the Moranbah Gas Project joint venture and the transfer of Property, Procurement and Security, and Health, Safety and Environment to Centrally Managed Expenses. This was partly offset by COVID-19 pandemic response related costs to ensure employees were able to safely work onsite and maintain plant availability.

1.4.3.3. Group Operations depreciation and amortisation

Group Operations depreciation and amortisation increased by $(53) million, or 11.0%.

• Thermal depreciation and amortisation was $(449) million, up 19.4%, reflecting a higher asset base at AGL Macquarie and AGL Loy Yang from increased reliability focused capital expenditure in previous years. The increased spend at AGL Macquarie is relative to a short depreciation schedule at Liddell Power Station given its committed closure. Additionally there was increased depreciation as a result of the completion of Barker Inlet Power Station during the year and the acquisition of the Kwinana Swift Power Station.
• Renewables depreciation and amortisation was $(50) million, up 6.4% due to a higher asset base.
• Other operations depreciation and amortisation was $(4) million, down 85.2% due the transfer of Property, Procurement and Security and Health, Safety and Environment functions to Centrally Managed Expenses.

1.4.4. Centrally Managed Expenses

AGL manages and reports a number of expense items including information technology under Centrally Managed Expenses. These costs are not reallocated to AGL’s operating segments because their management is the responsibility of various corporate functions.

Centrally Managed Expenses Underlying EBIT was $(413) million, down 43.4%, or $125 million. This included the transfer of $(61) million of costs from other functions, including the $(40) million of operating costs detailed in section 1.1.2.3 and $(21) million of depreciation costs. Excluding the impact of transferred functions, Underlying EBIT was down 18.3%, or $64 million, and operating costs were up 12.5%, or $38 million. This was primarily due to the increase in spend of $29 million in technology, data analytics and innovation in the Future Business & Technology function (including $18 million of costs that were capitalised in the prior year as part of the Customer Experience Transformation program and enterprise resource planning software upgrade), which was more than offset by the associated savings realised across the rest of the business. Additionally, there was an increase of $11 million in costs due to increased regulatory activity and insurance premiums. Depreciation and amortisation increased compared with the prior year as a result of the transfers noted above and completion of AGL’s enterprise resource planning software upgrade.

1.4.5. Investments

Investments comprises AGL’s interests in the ActewAGL Retail Partnership, the Powering Australian Renewables Fund, Advanced Microgrid Solutions Inc, Energy Impact Partners’ Fund, Activate Capital Partners, Solar Analytics Pty Limited, Sunverge Energy Inc and Ecobee Inc.

Perth Energy was reported within Investments at 31 December 2019. It has subsequently been fully integrated within Customer Markets, Group Operations and Centrally Managed Expenses.

ActewAGL Retail partnership contributed an equity share of profits of $16 million for the year compared with $31 million in the prior year. The decrease was due to increased competition and market activity, together with an increase in customer discounts.

1.5. Portfolio review

The portfolio review reporting for both the Electricity (section 1.5.2 ) and Gas (section 1.5.3 ) businesses provides a consolidated margin for each of the electricity and gas portfolios across operating segments. This is as an effective tool to present how value is generated in the business. The portfolio review combines the revenue from external customers and associated network and other costs, the costs of the procurement and hedging of AGL’s gas and electricity requirements, and the costs of managing and maintaining AGL’s owned and contracted generation assets to calculate the consolidated margin. A per unit rate ($/MWh for electricity and $/GJ for gas) is derived from each category of revenue and cost using the relevant associated volumes.

The tables in section 1.5.2 and 1.5.3 should be read in conjunction with section 1.7 to reconcile the segmental revenue and costs allocated to each portfolio with Group Underlying EBIT.

1.5.1. Portfolio Reporting Summary to Underlying Profit after Tax

1. ¹ Other margin includes other income from investments, and gross margin from Customer Markets and National Assets in Group Operations in the prior year.

1.5.2. Electricity portfolio

Electricity portfolio review reporting combines the Wholesale Markets, Customer Markets (Consumer and Large Business) and Group Operations businesses to reflect the procurement and hedging of AGL’s electricity requirements, the costs of managing and maintaining AGL’s owned and contracted generation assets, and the margin from external customers.

All volume generated is sold into either the National Electricity Market or Western Australian Wholesale Electricity Market (“the pool”) for which AGL receives pool generation revenue. Pool generation revenue is driven by volume and pool prices, which are set by the real-time market and differ by state. In the NEM, the total volume demanded by AGL customers is then purchased from the pool according to the geographical profile of customer demand and is reported as pool purchase costs. Where pool generation volumes exceed volumes purchased for customers, the net generation volume surplus drives revenue from indirect customers, which is incorporated within the pool generation revenue. Costs incurred in generating volume sold into the pool are reported as costs of generation, of which Wholesale Markets manages the cost of sales and Group Operations manages generation operation costs and asset depreciation. In Western Australia, these costs are managed through the Western Australian Wholesale Electricity Market.

• Pool generation volumes were 43,828 GWh, up 0.2%, driven by higher AGL Macquarie generation due to improved reliability and increased volume of coal deliveries, increased generation from Silverton and Coopers Gap Wind Farm, and the inclusion of Kwinana Swift volumes. This was partly offset by decreased generation at AGL Loy Yang due to the Unit 2 outage and lower volumes for AGL's Victorian hydro assets.
• Consumer volumes were 13,840 GWh, up 2.0%, largely due to growth in electricity customer services, with a minor offsetting decrease in average customer consumption due to milder weather.
• Large Business customer volumes were 10,564 GWh, up 8.1%, as a result of the acquisition of Perth Energy, partly offset by a change in customer mix and the reduction in customer demand due to COVID-19.
• Wholesale customer sales volumes were 15,945 GWh, up 0.9%, driven by increased consumption from AGL's existing customer base.

1. ¹ Wholesale customers revenue includes amounts from certain wholesale contracts that are treated as derivatives for statutory reporting purposes. In the statutory accounts the amounts associated with these contracts are recognised within cost of sales.

Total revenue was $7,172 million, up 2.3%.

• Revenue from Consumer customers was $4,091 million, up 0.6% due to a higher number of services to customers compared with the prior year, partly offset by the impact of increased regulation including the introduction of default offers.
• Large Business customer revenue was $1,823 million, up 5.1%, driven by the inclusion of revenue from the acquisition of Perth Energy, partly offset by the decline in revenue rate due to the decrease in wholesale costs.
• Wholesale Electricity and Eco Markets revenue was $1,162 million, up 5.3%, largely driven by an increase in green certificates sold as well as a small increase in volumes sold to Wholesale customers.
• Group Operations revenue was $96 million, down 7.7%, largely driven by lower insurance proceeds.

Total customer network and other costs of sales were $(3,312) million, up 8.0%.

• Total network costs were $(2,322) million, an increase of 3.4%, driven by higher Consumer customer sales volumes and the inclusion of Perth Energy network costs in the current year.
• Green compliance costs were $(584) million, up 17.7%, due to increased Consumer customer sales volumes and higher scheme compliance percentages, partly offset by the lower cost of large-scale generation certificates.
• Other cost of sales were $(406) million, up 24.9%, driven by higher solar feed-in-tariffs paid to Consumer customers due to an increase in solar volumes and the inclusion of Perth Energy.

Total fuel costs were $(1,013) million, down 4.7% compared with the prior year.

• Coal costs were $(747) million, down 3.0%, and on a per MWh basis decreased by $0.7 per MWh or 3.3%. This reflected increased deliveries of legacy coal contracts following improvements in delivery logistics and stockpile handling.
• Gas fuel costs were $(266) million, down 9.2%, driven by lower generation volumes and a lower unit cost rate due to supply mix benefits through the use of lower cost gas supplies.

1. ¹ Renewables includes PPA costs.

Total generation running costs were $(716) million, up 8.5%.

• Coal operating costs were $(374) million, up 7.8%, due to additional costs to maintain plant availability and COVID-19 pandemic response related costs to ensure employees could safely work onsite.
• Gas operating costs were $(58) million, up 26.1%, due to additional costs incurred at gas-fired power stations to support the portfolio during the AGL Loy Yang Unit 2 outage and costs associated with the Kwinana Swift Power Station, which was acquired as part of Perth Energy.
• Renewables costs were $(272) million, up 14.3% driven by the increased allocation of Wind PPA costs from Eco Markets to Wholesale Electricity, a result of the change in the relative value of LGCs and Electricity, and increasing output from the new Silverton and Coopers Gap wind farms.
• Other costs were $(12) million, down 58.6% due to the inclusion of Kwinana capacity revenue.

Depreciation and amortisation was $(499) million, up 18.2%, reflecting a higher asset base at AGL Macquarie and AGL Loy Yang from increased reliability focused capital expenditure in previous years. The increased spend at AGL Macquarie is relative to a short depreciation schedule at Liddell Power Station given its committed closure.

1. ¹ Pool generation revenue and pool purchase costs include amounts from certain wholesale contracts that are treated as derivatives for statutory reporting purposes. In the statutory accounts the amounts associated with these contracts are recognised within cost of sales.

Net pool generation revenue and pool purchase costs were $138 million, down 69.2%, reflecting higher generation and customer volumes but at lower pool prices. The net derivative revenue of $26 million has increased by $283 million, or $6.5 per MWh driven largely by the performance of wholesale electricity derivatives, with pool prices significantly lower than contracted prices in the second half of the year.

In addition to the commentary above, Electricity portfolio margin is discussed in sections 1.4.1 and 1.4.2 .

1.5.3. Gas portfolio

The gas portfolio review reporting combines the Wholesale Markets and Customer Markets (Consumer and Business) businesses to reflect the procurement and hedging of AGL’s gas requirements and the margin from external customers.

Total customer sales volume were 155.5 PJ, a decrease of 11.6 PJ or 6.9%.

• Consumer customer volumes were 58.2 PJ, up 1.6%, due to the impact of cooler weather relative to the prior year on customer average consumption, plus the impact of customer service growth.
• Large Business customer volumes were 15.8 PJ, down 3.7%, due to a loss of customers resulting from the challenges of sourcing gas in a tight market as AGL's legacy lower cost gas supply contracts roll off, partly offset by the inclusion of Perth Energy volumes following acquisition.
• Wholesale Markets and generation volume were 81.5 PJ, a decrease of 12.7%, driven by lower volumes from AGL’s existing wholesale customer base as well as lower AGL Torrens generation compared with the prior year, partly offset by higher generation from the Barker Inlet Power Station.

Total revenue was $2,496 million, down 5.0%.

• Consumer revenue was $1,534 million, up 0.3% driven by higher sales volumes as a result of growth in the number of services to customers, partially offset by the impact of customers switching to lower-priced products.
• Large Business customers revenue was $137 million, down 18.5% due to a decrease in volumes, partly offset by the inclusion of Perth Energy revenue.
• Wholesale customer revenue was $825 million, down 11.1%, largely driven by lower customer volumes. Rate per unit increased due to a change in customer mix.

Total network costs and other cost of sales were $(584) million, up 1.6%, driven by higher Consumer sales volumes as a result of growth in customer services and the inclusion of Perth Energy network costs in the current year.

Total wholesale costs were $(1,258) million, down 5.6%, due to lower volumes. The lower cost of gas was driven by the lower volumes sold during the year resulting in a supply mix benefit through the use of lower cost gas supplies. This was partly offset by the increase in haulage and storage costs due to an increase in storage capacity.

Natural Gas margin was $(29) million, up 50.0%, primarily due to the decrease in field development costs relating to the Moranbah Gas Project joint venture and increased revenue from gas sales.

In addition to the commentary above, Gas portfolio margin is discussed in sections 1.4.1 and 1.4.2 .

1.6. Consolidated financial performance by operating segment

1.7. Portfolio review reconciliation

Notes

(a) Other AGL includes Natural Gas Underlying EBIT.

(b) Key adjustments include:

• Wholesale Markets electricity pool sales in the statutory accounts has been reallocated to cost of sales (net portfolio management) in the Portfolio Review where it is combined with pool purchase costs and derivatives to reflect AGL’s net position.

• Wholesale Markets other revenue in the statutory accounts has been reallocated to cost of sales (generation running costs) in the Portfolio Review including ancillary services revenue, brown coal sales and wind farm asset management fees.

• Within Wholesale Markets, derivatives from certain wholesale contracts are recognised within cost of sales in the statutory accounts. In the Portfolio Review the revenue and costs have been separately disclosed.

• Intra-segment and inter-segment eliminations include: Gas sales from Wholesale Gas to Wholesale Electricity; gas sales from Group Operations (Natural Gas) to Wholesale Markets. Elimination adjustment also includes the reallocation of green costs from Wholesale Markets (Eco-Markets) to Consumer and Business customer other cost of sales.