AGL Energy Limited
GovernanceGovernance
Governance body oversight and management's role
Index: paragraph 6 maps to sections 16.1, 16.1.1, 16.2 and 16.2.1 (pp.136–138); 6(b)(ii) also to 14.1.
Board and committees (p.136). The Board reviews and approves strategic direction, including the implications of climate-related risks and opportunities for business model, financial position, financial performance and cash flows. Responsibilities sit in formal Charters, reviewed at least every two years. The Safety & Sustainability Committee oversees the processes for identifying, assessing and managing climate-related risks and opportunities, recommends material climate-related targets to the Board and monitors progress. The Audit & Risk Management Committee reviews the financial components of the climate disclosures. The People & Performance Committee advises on climate in remuneration. The Board considers performance against key climate targets quarterly.
Skills (pp.136–137). The FY26 Board Skills Matrix review included a consultant benchmarking exercise and identified Energy Transition and ESG as a priority area.
Management (p.137). The Managing Director & CEO translates strategy into plans and delegates to the Executive Team, which collectively is accountable for managing climate-related risks. Tier 1 risks are reviewed at least twice a year.
Remuneration (p.138). Climate metrics sit in the short-term and long-term incentive plans; 7.8% of total executive remuneration recognized in FY26 is linked to climate considerations.
StrategyStrategy
Climate-related risks and opportunities
Index: 10(a)–(d) map to section 14.2 (pp.117–130); the identification approach is in 14.1 (p.116).
Time horizons (p.117). Short-term FY27–FY30, medium-term FY31–FY35, long-term FY36+. They are selected to align with AGL's strategic planning horizons, with key milestones in FY30 and 2035 for energy portfolio transition plans, and are used in strategic decision making.
Transition risks (pp.118–123). Policy and regulatory changes; access to capital; portfolio transition delay; changing customer preferences; stakeholder expectations.
Physical risks (pp.124–127). Vulnerability of AGL's energy assets to climate-related hazards (acute: bushfire; chronic: drought, wind drought); vulnerability of non-AGL infrastructure to climate-related hazards.
Opportunities (pp.127–130). Customer decarbonization; energy portfolio transition.
Each item carries time-horizon icons keyed to the p.117 legend. Eight carry short, medium and long-term icons; changing customer preferences carries medium and long-term icons only, and its text calls the short-term impact immaterial (p.122).
Business model and value chain
Index: 13(a) and 13(b) map to section 14.2 (pp.117–130) and to a vulnerability section numbered 12.3, which matches 14.3 on exposure of business activities (p.131).
Value chain (p.107). AGL shows an electricity value chain (upstream supply chain; grid-scale generation and storage; transmission and distribution; retailing; customer end use) and a gas value chain (upstream supply chain; production, transport and storage; transmission and distribution; retailing; customer end use). AGL operates the largest privately owned electricity generation portfolio in Australia and owns and operates the Loy Yang Mine. It does not own or operate upstream gas production or transmission and distribution infrastructure.
Where effects concentrate (14.2). Each item says where it is concentrated: access to capital mainly affects the operated and contracted generation portfolio, with flow-on effects to trading and retailing (p.119); changing customer preferences are concentrated in electricity and gas retail (p.122); physical risk to energy assets is concentrated in operated electricity assets (p.124).
Exposure by activity (p.131). Thermal generation, renewables and firming, electricity retail and gas retail are shaded higher or lower exposure for each risk and opportunity. FY26 EBITDA: Integrated Energy $2,032m / 84%; Customer Markets $392m / 16%. Coal-fired generation is 48% of operated and contracted capacity.
Strategy and decision-making
Index: 14(a)–(c) map to sections 12, 12.1, 13, 14.2 and 17.2.
Transition plan (pp.108–109). The 2025 Climate Transition Action Plan (CTAP) was approved by the Board and received majority support in a non-binding Say on Climate vote at the 2025 Annual General Meeting. It sets an ambition of 12 GW of new renewable and firming capacity by the end of 2035 (6 GW targeted by FY30); coal exit by the end of FY35; Scope 1 and 2 reductions against FY19 of 17% (FY24–FY26), 19% (from FY27) and 52% (FY35), then net zero following coal closure; and an ambition of net zero Scope 1, 2 and 3 by 2050. Updated plans are expected in 2028.
Resourcing (pp.109–110). About $10 billion of balance sheet capital across the transition, heavily weighted toward firming. Expected capital allocation to climate solutions: 79% (FY27–30), 63% (FY31–35), 69% (FY27–35).
Dependencies and assumptions (p.141). Third-party coal closures and grid decarbonization; stable supportive policy; unlocking non-market barriers; investment appetite; demand growth; electrification uptake; affordability; technology costs; offsets; macroeconomic conditions.
Mitigation and adaptation (14.2). Physical climate considerations are built into asset risk management, maintenance and capital planning (p.125). Customer offerings include EV solutions, flexible load products and a virtual power plant (p.128).
Progress (p.109). Annual Scope 1 and 2 reduction target outperformed each year FY24–FY26.
Financial position, financial performance and cash flows
Index: 15(a)–(b), 16(a), 16(b) and 16(d) map to section 14.2; 16(c) to section 12.1.
Each risk and opportunity in 14.2 (pp.117–130) has tables of potential and current financial effects by line item. No significant risk has been identified for the carrying value of assets and liabilities for FY27 (p.117). Quantification is described as illustrative. Quantified potential effects:
- Access to capital (p.119): a 50 to 200 bps rise in the cost of debt could raise average annual interest expense by approximately $10–$50 million (short term), $20–$80 million (medium), $20–$90 million (long).
- Portfolio transition delay (p.120): a 1–2 year delay could reduce NPAT by $30–50 million p.a. (short) and $20–40 million p.a. (medium), and raise it by $50–100 million p.a. (long).
- Changing customer preferences (p.122): EBITDA impact $50–$80 million (medium), $70–$100 million (long).
- Drought (p.125): impacts of up to $150 million, $200 million and $250 million to EBITDA over two years (short, medium, long).
- Customer decarbonization (p.128): EBITDA $40 million p.a. (short), $90–120 million p.a. (medium), $200+ million p.a. (long).
- Energy portfolio transition (p.129): EBITDA around $400 million (short), $700 million (medium), $1,300 million (long); about $10 billion of balance sheet capital, funded by operating cash flows and debt. Current effects: Nil for six of the seven risks (pp.118–126); FY26 capital expenditure in renewable and firming assets was $632 million (p.130).
Climate resilience and scenario analysis
Index: 22(a)–(b) map to sections 15, 17.3, 17.1 and 17.2 (pp.132–135, 139–144).
Scenarios. Low-warming: 1.5° rapid transition (Scenario 1; AEMO 2024 ISP Green Energy Exports; NEM carbon budget 357 MtCO2e for 2026–2052; AGL coal stations close in FY30). High-warming: above 2° with build constraints (Scenario 4; AEMO 2024 ISP Progressive Change; ~2.6°; 1203 MtCO2e; AGL closures Dec 2033, June 2035), plus physical Scenario B (~2.7°, SSP-2-4.5). Transition modeling: FY25, with ACIL Allen; physical modeling: FY24, with Aon (pp.139, 142–144). Horizons: short FY26–FY30, medium FY31–FY35, long FY36–FY50. Scope: energy portfolio and energy retail business (p.142).
Assessment. Under both, the two strategic pillars would not fundamentally change; delivery would need a faster pace and scale (low-warming) or an adaptive approach (high-warming) (pp.132, 134). AGL considers its business able to remain resilient under the low-warming scenario, and its strategy resilient to the transition effects of the high-warming scenario, over the short, medium and long term, subject to supportive policy and regulatory settings, market conditions and, for low-warming, access to capital (pp.133, 135). Under low-warming, its development pipeline, flexible balance sheet and prudent capital management would support acceleration (p.133).
Limit. Physical modeling assesses exposure by asset location only, not asset type, vulnerability or mitigation, so hazard impact has not been assessed (p.144).
Risk ManagementRisk Management
Processes for identifying, assessing and managing climate-related risks
Index: 25(a)(i)–(vi), 25(b) and 25(c) map to section 14.1 (p.116).
Risks. AGL maintains an enterprise-wide risk management framework embedded in business processes, strategy setting and operational activities, using defined thresholds for likelihood and consequence across six dimensions: Commercial/profitability; Regulatory compliance; Reputation, community and customer; Environment; Health and safety; and People. Many Tier 1 Strategic Risks contain climate-related aspects. Climate-related risks are identified and assessed top-down and bottom-up, drawing on risk registers, strategic and business planning, climate-related scenario analysis and consultation with senior management and subject matter experts, and are monitored through periodic climate risk reviews and management reporting. The Climate Risk Management Program was developed to align identification and disclosure practices with AASB S2. The test for whether a risk could reasonably be expected to affect prospects considers high-impact, low-likelihood catastrophic events (for example extreme bushfire) and/or risks that could significantly impact delivery of strategy.
Opportunities. AGL's two strategic pillars are the framework for identifying value pools. Assessment weighs qualitative and quantitative factors, top-down and bottom-up, and whether each activity is important to delivering strategy or expected to be strategically significant to stakeholders.
Metrics & TargetsMetrics and Targets
Climate-related metrics
Index: 29(a) maps to 13.1 and 17.4; 29(b)–(d) to 14.3; 29(e) to 12.1; 29(f) to 12.2; 29(g) to 16.2.1.
Emissions, MtCO2e (13.1, p.112). Scope 2 is location-based; FY26 is estimated.
| FY25 | FY26 | |
|---|---|---|
| Scope 1 | 30.4 | 29.1 |
| Scope 2 | 0.25 | 0.29 |
| Scope 1 and 2 | 30.7 | 29.4 |
| Scope 3 | 24.5 | 23.8 |
| Scope 1, 2 and 3 | 55.1 | 53.3 |
FY26 Scope 3 is 8.3 (supply of electricity to customers), 5.4 (supply of natural gas to customers), 9.4 (end use of coal sold to Loy Yang B) and 0.7 other; material sources fall in GHG Protocol Category 3 and Category 11 (p.144). FY25 Scope 3 was restated to an updated calculation methodology (pp.112, 145). Scope 1 and 2 follow the NGER (Measurement) Determination for facilities under operational control; no material non-consolidated entities are excluded (pp.144–145). AGL adopted relief C4(b) for Scope 3 and C3 for comparatives, and reports selected Scope 3 and comparative data voluntarily (p.106).
Other metrics. Capital deployment: $573 million climate solutions capex (42% of total) and $156 million gas-powered generation (p.109). Carbon price: the potential future cost of carbon offsets is considered in financial planning and capital approvals, using approximately $20/tCO2e (nominal) on average over FY36–FY50 (p.110). Remuneration: 7.8% of executive remuneration linked to climate (p.138).
Climate-related targets
Index: 33–36 map to sections 13, 13.1 and 13.2 (pp.111–115).
Scope 1 and 2 targets (p.112). Targets are absolute and apply at consolidated entity level; emissions targets are gross unless referred to as net (p.111). FY19 baseline: 43.2 MtCO2e (Scope 1 42.7; Scope 2 0.5). Targets cover all greenhouse gas types in the NGER Scheme and the GHG Protocol.
| Reduction in annual Scope 1 and 2 emissions | Target |
|---|---|
| FY26 | 17% |
| FY27–FY34 | 19% |
| FY35 | 52% |
| Following closure of coal-fired power stations (planned FY36) | >90%; Net zero |
FY26: 31.9% reduction (FY25: 29.1%), exceeding the 17% target. Targets were not derived using a sectoral decarbonization approach; Australian climate and energy policy and the Paris Agreement were considered (pp.112, 142).
Ambitions, not treated as targets under AASB S2 (pp.111–112). Scope 3 reduction of 60% following coal closure (FY26: 2.5%); Scope 1, 2 and 3 reduction of 90% and net zero by 2050.
Offsets (pp.110, 113). Not used for interim gross targets. AGL plans to offset residual emissions (<10% of FY19 Scope 1 and 2) where necessary, subject to commercially viable offsets; verification schemes will be considered at the relevant time; nature-based and technological removals may be considered.
Other targets (pp.113–114). 2.1 GW new renewable and firming capacity by FY27 (2,126 MW in FY26); at least 3 GW grid-scale batteries by FY30; 300 MW cumulative customer assets by FY27 (196 MW in FY26).