Electric Utilities, Grids and Rate Regulation

An electric utility is a business whose price is set by the government. In return for a monopoly over the wires, and often over generation, in a territory, it accepts an obligation to serve every customer and lets a regulator decide what it may charge. The regulator does not set a profit; it sets a revenue requirement: operating costs, depreciation and taxes recovered at cost, plus a return on the money invested in the network (the rate base) at an allowed return on equity (ROE) that averaged ~9.77% in US electric rate cases in 2025 and ~9.79% in the first half of 2026 (S&P Global Regulatory Research Associates, excluding limited-issue riders; reported). That formula explains almost everything about the industry: a utility grows its earnings by growing the rate base, so its management is paid to spend capital; its investors treat it as a bond with a growth kicker; and the binding constraint is not demand or technology but what customers and their elected representatives will tolerate on the bill. By 2025–26 that constraint was being tested from three directions at once: a capital-spending wave (US investor-owned utilities projected ~$208bn of capex in 2025 and more than $1.1 trillion over 2025–29; Edison Electric Institute, Oct 2025), the first sustained load growth in two decades (data centres above all), and liability for wildfires and storms large enough to bankrupt a utility (PG&E, 2019) or drain a state fund (the Eaton fire, Jan 2025). This section explains how utilities are structured and regulated, how a rate case turns capital into price, why the capex wave and load growth push bills in opposite directions, how liability became an existential cost, why utility M&A came back in 2025–26, and how the same model works, or fails, outside the US. Two companion files give a stylized revenue-requirement and bill-impact worked example and a checklist for reading a rate case.