Rising Electric Rates Tied to Distribution Spending, Disasters and Some Clean Energy Programs, Study Says

A recent Lawrence Berkeley National Laboratory study analyzing U.S. retail electricity rates from 2019-2024 identified key drivers for inflation-adjusted increases in 17 states, including rising utility distribution/transmission spending, disaster recovery costs, and natural gas price volatility. While market-based renewable energy growth did not correlate with higher prices, the report highlighted a critical shift where surging demand from data centers is now outpacing supply in regions like PJM, leading to significant price spikes and potential shortages, reversing historical trends where increased sales lowered costs. This dynamic, alongside the impact of net metering shifting costs to non-solar customers and the unexamined role of investor-owned utility profit margins, presents complex challenges for energy infrastructure investment and industrial consumers.

Analysis

The Lawrence Berkeley National Laboratory study, spanning 2019-2024, highlights key drivers behind inflation-adjusted electricity rate increases in 17 U.S. states, including California and New York. A significant factor is the 50% rise in utility distribution and transmission capital expenses from 2019 to 2023, now constituting half of national utility spending. Additionally, disaster recovery and mitigation costs, particularly wildfire spending in California, added approximately 4 cents per kilowatt-hour, increasing monthly bills by an average of $30.

While renewable portfolio standards (RPS) contributed modestly to rate increases (+1 cent/kWh), 75% of market-based wind and solar growth showed no correlation with higher prices and some evidence of price reduction. Conversely, natural gas price volatility, which fueled 43% of U.S. electricity in 2024, significantly impacted rates, with the Ukraine-Russia war driving a 1 cent/kWh average increase in 10 gas-exposed states between 2021 and 2023. Net metering programs also contributed to rate increases, shifting costs to non-solar customers, estimated at $8.5 billion in California in 2024.

A critical emerging risk is the accelerating electricity demand from data centers, which is beginning to outpace supply and infrastructure capacity. Historically, increased sales lowered prices, but regions like PJM (Maryland/Virginia) are already experiencing high wholesale and residential rate spikes due to data center growth, with PJM anticipating a 30-gigawatt shortfall in coming years. This suggests a reversal of traditional demand-side economics, posing significant future price pressures.

The study, while identifying correlations, did not analyze structural factors like utility ownership and profit margins, which are pertinent to the debate. Investor-owned utilities, representing 70% of the California market, earn profits as a percentage of capital investments, with returns on equity (ROE) around 10% in California, potentially incentivizing excessive infrastructure spending and contributing to higher rates compared to publicly owned utilities.

Key Decisions for Investors

• Monitor regional electricity demand and supply dynamics, particularly in areas with high data center concentration, as these regions face significant upward pressure on wholesale and retail electricity prices.
• Evaluate utility companies' capital expenditure plans and regulatory environments, especially concerning distribution/transmission spending and disaster recovery costs, as these are direct drivers of rate increases passed to consumers.
• Assess exposure to natural gas price volatility for utilities and industrial consumers, given its substantial impact on electricity costs, and consider hedging strategies or investments in regions with diverse energy mixes.
• Consider the long-term implications of rising electricity costs on industrial operations and consumer spending, potentially impacting sectors with high energy consumption or those serving regions with rapidly escalating utility bills.