Electricity Markets and Economics Training Course

Participants can explain how demand and marginal generation set short-run prices.

• Hourly load profiles analysed using peak, shoulder and baseload periods
• Price elasticity of electricity demand under retail tariff structures
• Marginal cost curves built from fuel, carbon and variable operating costs
• Merit-order dispatch determines marginal plant selection and clearing prices
• Scarcity pricing signals tight capacity and reliability risk conditions
• Negative prices explained through inflexibility, subsidies and renewable output

Participants can compare generation technologies using cost, performance and operational criteria.

• Capital expenditure, fixed costs and variable costs separated clearly
• Heat-rate calculations convert fuel prices into marginal generation costs
• Levelized cost of electricity interpreted alongside system integration costs
• Capacity factors and availability distinguish energy output from plant capability
• Start-up costs and ramp rates shape thermal dispatch decisions
• Wind and solar variability measured through production profile analysis

Participants can assess the rules and incentives of wholesale electricity markets.

• Day-ahead auctions clear supply offers against demand forecasts
• Intraday trading corrects forecast errors before physical delivery
• Uniform pricing and pay-as-bid mechanisms compared using incentives
• Gate closure rules allocate forecasting and imbalance responsibilities
• Bid formats accommodate complex thermal unit operating constraints
• Settlement intervals affect price signals, metering and flexibility revenues

Participants can explain how balancing actions and ancillary services maintain system security.

• Balancing energy resolves real-time deviations from scheduled generation
• Frequency response services stabilise systems following sudden supply losses
• Operating reserves classified as spinning, non-spinning and replacement reserves
• Imbalance pricing assigns costs for deviations from market positions
• Co-optimisation of energy and reserves improves dispatch efficiency
• Ancillary-service procurement creates revenue opportunities for flexible assets

Participants can analyse how network constraints affect dispatch, prices and investment.

• Transmission constraints limit economically efficient generation dispatch patterns
• Congestion rents arise when constrained lines separate market prices
• Locational marginal pricing separates energy, congestion and loss components
• Zonal pricing aggregates constraints within defined trading areas
• Financial transmission rights hedge congestion exposure between locations
• Network reinforcement assessed against congestion costs and reliability benefits

Participants can assess renewable revenues under variable output and changing market conditions.

• Capture price measures generation-weighted revenues against average market prices
• Cannibalisation effects reduce solar and wind revenues during correlated output
• Curtailment distinguishes resource availability from deliverable electricity production
• Forecast error costs affect variable renewable generator net revenues
• Hybrid projects combine generation, storage and grid connection economics
• Renewable support schemes compared with merchant revenue arrangements

Participants can build and interpret a structured electricity market data set.

• Load, generation and price data aligned by settlement interval
• Weather-normalisation separates temperature effects from underlying demand trends
• Residual demand calculated after variable renewable generation output
• Supply-stack models estimate marginal plant and hourly clearing price
• Scenario assumptions documented for fuel, carbon and capacity changes
• Forecast uncertainty expressed through sensitivities and probability ranges

Participants can evaluate capacity-market designs and their implications for reliability.

• Resource adequacy measures expected demand against dependable supply capacity
• Loss of load expectation quantifies reliability under stressed conditions
• Capacity auctions procure future availability through competitive commitments
• Reliability options link capacity payments with scarcity-price obligations
• Strategic reserves retain emergency capacity outside normal energy markets
• Capacity credits reflect renewable and storage contribution during peak periods

Participants can evaluate battery storage economics across multiple electricity revenue streams.

• Battery round-trip efficiency links charging costs to discharge revenues
• Arbitrage value calculated from charging and discharging price spreads
• Revenue stacking combines energy, reserve and network-service payments
• Cycle limits and degradation costs incorporated into dispatch decisions
• Duration requirements tested against peak demand and outage scenarios
• Pumped hydro and batteries compared by duration, cost and response

Participants can assess demand-side flexibility and electrification impacts on market outcomes.

• Demand response products reward load reduction during system stress
• Time-of-use tariffs shift consumption toward lower-cost periods
• Industrial load flexibility assessed through process and production constraints
• Electric vehicle charging profiles affect distribution and wholesale peaks
• Heat pump adoption changes seasonal demand and capacity requirements
• Baseline methodologies determine measured demand-response delivery and payments

Participants can compare retail pricing structures and customer risk allocation.

• Retail tariffs separate energy, network, policy and tax components
• Fixed-price contracts transfer wholesale price risk to suppliers
• Indexed tariffs pass market-price exposure through to customers
• Demand charges recover network costs from coincident peak usage
• Supplier margin analysis links customer portfolios with hedge positions
• Consumer protection rules address billing transparency and switching rights

Participants can evaluate PPA structures, allocation of risks and buyer economics.

• Physical PPAs link contracted generation with buyer delivery arrangements
• Virtual PPAs settle contract-for-difference payments against market prices
• Contracted volume shapes profile, basis and balancing risk exposure
• Price escalators index PPA payments to inflation or commodity measures
• Credit support provisions protect parties against default and termination
• Additionality claims assessed through project financing and procurement timing

Participants can compare hedging instruments and quantify key power-market exposures.

• Forward contracts lock future power prices for defined delivery periods
• Futures contracts use standardised terms and daily margining processes
• Options provide price protection while retaining favourable market upside
• Basis risk arises between hedge locations and physical exposure
• Volume risk measures mismatch between contracted and actual consumption
• Value-at-risk estimates potential portfolio losses under price volatility

Participants can incorporate carbon costs and environmental attributes into electricity economics.

• Emissions factors convert generation output into carbon compliance obligations
• Carbon pricing changes marginal costs and merit-order positions
• Allowance markets allocate tradable emissions permits under capped systems
• Renewable energy certificates document generation attributes separate from electricity
• Guarantees of origin support renewable electricity claims in relevant markets
• Carbon pass-through measures price impacts on electricity consumers

Participants can identify market-power risks and assess regulatory responses.

• Pivotal supplier analysis identifies generators essential to meeting demand
• Residual supply index measures competitive pressure during peak periods
• Economic withholding restricts capacity to raise wholesale clearing prices
• Bid mitigation rules constrain conduct under defined market conditions
• Unbundling separates network control from competitive generation activities
• Regulatory impact assessment tests efficiency, equity and implementation effects

Participants can appraise electricity assets using market revenues, costs and risk scenarios.

• Project cash flows integrate capital costs, operating costs and revenues
• Net present value discounts future cash flows using required returns
• Internal rate of return compared with hurdle-rate investment criteria
• Merchant tail assumptions estimate post-contract market revenue exposure
• Sensitivity analysis tests fuel, carbon, price and curtailment assumptions
• Scenario analysis compares policy, demand and technology development pathways

Participants can assess policy and market-reform options against economic and reliability objectives.

• Energy-only markets rely on scarcity prices to reward adequacy
• Contract-for-difference schemes stabilise low-carbon investment revenues
• Renewable auctions compare price, delivery and non-price qualification criteria
• Coal retirement schedules affect capacity margins and regional prices
• Interconnection expands trading opportunities and shared reserve provision
• Just-transition considerations assess distributional impacts of market reform

Participants can assemble an evidence-based electricity market assessment for a defined decision.

• Market boundary defined by geography, products, participants and time horizon
• Demand outlook combines historic consumption, weather and electrification drivers
• Generation pipeline screened by technology, location and commissioning probability
• Revenue stack maps energy, capacity, ancillary-service and contract income
• Risk register records market, policy, network and counterparty exposures
• Recommendation criteria align commercial returns with reliability and policy objectives

Participants can build, review and present a complete electricity market assessment and investment recommendation.

• Assemble supply, demand, network and policy evidence into one assessment
• Model dispatch, price formation and renewable capture-price assumptions transparently
• Evaluate asset revenues under base, upside and downside scenarios
• Compare contract, hedge and market-design responses to identified risks
• Review findings against economic logic, data quality and stakeholder interests
• Present investment recommendation, assumptions, risks and priority actions clearly