Energy Economics and Pricing Training Course

Participants can map the market arrangements determining electricity prices and revenues.

• Wholesale, balancing, capacity and ancillary-service market functions
• Roles of generators, retailers, system operators and network owners
• Nodal and zonal pricing compared using congestion outcomes
• Day-ahead, intraday and real-time market timing conventions
• Settlement periods, imbalance charges and metering data requirements
• Regulated tariffs distinguished from competitive retail price components

Participants can derive wholesale price outcomes from supply-stack and demand assumptions.

• Merit-order curves constructed from plant availability and marginal costs
• Marginal plant selection under changing demand and outage conditions
• Demand curves adjusted for weather, economic activity and efficiency
• Negative prices explained through inflexibility, subsidies and oversupply
• Interconnector flows incorporated into regional supply-demand balances
• Scarcity pricing linked to reserve margins and value of lost load

Participants can assess fuel and carbon drivers within power and heat prices.

• Gas, coal and oil benchmarks interpreted by delivery location
• Clean spark and dark spreads calculated from fuel efficiencies
• Carbon allowance costs incorporated into thermal generation offers
• Heat rates converted between fuel input and electricity output
• Currency effects tested for internationally traded fuel contracts
• Fuel-switching thresholds estimated using relative commodity and carbon prices

Participants can quantify the operating and revenue drivers of renewable assets.

• Capacity factor estimated from resource data and technical availability
• Generation profiles matched against hourly market-price patterns
• Curtailment losses separated from planned maintenance and forced outages
• Degradation assumptions applied to solar, wind and battery assets
• Network connection costs allocated within project cash flow models
• Renewable certificates and guarantees of origin valued separately

Participants can calculate comparable cost and value metrics for energy projects.

• LCOE calculated using discounted lifetime costs and electricity output
• Net present value built from project cash flows
• Internal rate of return interpreted alongside multiple investment criteria
• Weighted average cost of capital derived from debt and equity
• Nominal and real cash flows treated with consistent inflation assumptions
• Tax, depreciation and residual value incorporated into valuations

Participants can build an auditable spreadsheet model for an energy asset.

• Model architecture separates inputs, calculations, outputs and checks
• Timeline conventions align construction, operations, debt and reporting periods
• Operating expenditure schedules linked to inflation and asset availability
• Revenue formulas connect generation volumes, prices and contract terms
• Error checks identify broken links, sign errors and timing gaps
• Assumption register documents sources, owners and update dates

Participants can create transparent energy price forecasts for commercial decisions.

• Fundamental forecasts combine demand, capacity, fuels and interconnection assumptions
• Forward curves interpreted for market expectations and hedging prices
• Scenario ranges built around central, downside and upside cases
• Regression outputs assessed for explanatory relevance and limitations
• Seasonality modelled through monthly, daily and intraday demand patterns
• Forecast governance distinguishes observable data from management judgement

Participants can assess whether renewable output earns the forecast market price.

• Capture price calculated from generation-weighted hourly market revenues
• Capture rate compared against baseload and average market prices
• Cannibalisation effects estimated as renewable penetration increases
• Weather correlations tested between output, demand and spot prices
• Curtailment scenarios reflected in volume and revenue forecasts
• Merchant tail assumptions reviewed against long-term market fundamentals

Participants can compare PPA structures through cash flow and risk allocation.

• Physical and financial PPAs distinguished by delivery and settlement mechanics
• Fixed-price, indexed and floor-collar structures compared financially
• Pay-as-produced and baseload volume profiles tested against demand
• Basis risk measured between generation node and consumption location
• Credit support, collateral and termination provisions valued qualitatively
• Contract tenor aligned with debt maturity and procurement objectives

Participants can evaluate energy supply costs and tariff choices for large consumers.

• Retail bill components separated into commodity, network, tax and service charges
• Load-factor analysis identifies demand-charge and capacity-cost exposure
• Time-of-use tariffs modelled against interval consumption data
• Hedging ratios tested against budget certainty and market opportunity
• Request-for-proposal evaluation criteria weighted for price, risk and service
• Procurement calendar aligned with contract expiry and market liquidity

Participants can identify, quantify and treat major commercial energy risks.

• Risk registers classify price, volume, basis, credit and regulatory exposures
• Sensitivity tables rank variables by impact on project value
• Monte Carlo simulation applied to correlated price and production uncertainty
• Value at Risk estimated for defined portfolio confidence levels
• Futures, swaps and options matched to specific risk exposures
• Hedge effectiveness assessed against physical position and accounting constraints

Participants can evaluate revenue stacks and constraints for storage and flexible assets.

• Battery dispatch optimised against price spreads and operating constraints
• Round-trip efficiency and degradation incorporated into storage revenues
• Ancillary-service revenues assessed alongside wholesale arbitrage income
• Co-located storage evaluated with renewable generation and grid limits
• Demand response value calculated from avoided peak and imbalance charges
• Revenue stacking tested for double counting and contractual conflicts

Participants can assess capacity revenues and reliability obligations in investment cases.

• Capacity mechanisms compared across reliability options and payment designs
• Capacity accreditation adjusted for availability and derating factors
• Reliability options linked to scarcity prices and performance obligations
• Reserve margin metrics interpreted against peak-demand forecast uncertainty
• Firm capacity value estimated for variable renewable generation
• Non-delivery penalties incorporated into capacity revenue scenarios

Participants can incorporate network constraints and charges into commercial analysis.

• Congestion rents explained through constrained transmission and locational prices
• Loss factors applied to generation, consumption and settlement volumes
• Connection queue risk assessed for project development schedules
• Transmission charges modelled as fixed, volumetric and locational costs
• Distribution-use-of-system charges analysed from load and tariff data
• Grid reinforcement assumptions tested within project development scenarios

Participants can evaluate auction bids and support mechanisms using project economics.

• Contracts for difference modelled against merchant price outcomes
• Feed-in tariffs compared with premiums and production tax credits
• Auction bid ceilings derived from target returns and financing assumptions
• Indexation rules tested against inflation, currency and cost escalation
• Negative-price clauses assessed for lost support and dispatch incentives
• Bid bonds, completion milestones and penalties incorporated into risk

Participants can assess financing constraints that affect energy project value.

• Debt service coverage ratios calculated from available project cash flow
• Loan-life coverage ratios linked to debt sizing decisions
• Construction risk allocated among sponsors, contractors and lenders
• Offtaker credit quality assessed through payment and termination exposure
• Financial covenants tested under downside production and price cases
• Bankability gaps identified in contracts, permits and revenue assumptions

Participants can compare decarbonisation options using cost, emissions and reliability metrics.

• Marginal abatement cost curves rank emissions-reduction investment options
• Scope 1 and 2 emissions quantified using recognised accounting methods
• Electrification economics compared with fuel switching and efficiency measures
• Portfolio diversification tested across technologies, regions and contract tenors
• Transition scenarios translated into demand, price and asset assumptions
• Stranded-asset risk assessed under policy and technology change cases

Participants can prepare decision materials that make assumptions, risks and trade-offs explicit.

• Investment committee papers structure recommendation, evidence, risks and approvals
• Tornado charts communicate sensitivity results to non-specialist decision makers
• Scenario narratives distinguish forecast assumptions from contingent risks
• Model review checklists test logic, traceability and version control
• Decision gates align development spend with evidence and risk reduction
• Post-investment reviews compare realised performance against approved assumptions

Participants can build, review and present a complete energy investment or procurement case with price assumptions, cash flows, risks and a justified recommendation.

• Define decision scope, stakeholders, constraints and commercial success criteria
• Build integrated volume, price, cost and financing assumptions
• Calculate valuation metrics, capture prices and contract cash flows
• Test downside scenarios for fuel, carbon, output and curtailment
• Review model controls, assumptions register and risk treatment actions
• Present recommendation, alternatives, sensitivities and implementation priorities