The affordability of electricity is a growing problem around the world. Rapidly rising electricity costs are straining household and corporate budgets, and electric power systems in many markets are being asked to do more at precisely the moment their product has become more expensive. If not addressed, cost concerns will put a damper on the financial performance of companies across the electric power ecosystem—and potentially make countries less economically competitive.
Our analysis points to three core drivers of rising electricity costs: imbalances between supply and demand, massive grid investments, and regulations that were designed for market conditions of the past. But solutions are available for all stakeholders in the ecosystem.
In the short term, regulators can better allocate costs and redesign incentives. In the medium term, utilities can optimize how they operate their existing system and invest in new capacity. Longer-term, policymakers can partner with industry players to reshape the electricity ecosystem and ensure that the supply of affordable, reliable power matches growing demand. Some markets have already started to implement these measures, slowing the growth of electricity costs. Stakeholders in other markets should follow suit.
The New Cost Reality
Global demand for electricity is now growing faster than for any other major energy source. The shift is sharpest in developed markets, where consumption had been broadly flat for some 15 years but is now moving markedly upward. (See Exhibit 1.) In the US, the summer of 2026 produced a run of records for weekly electric output across the lower 48 states, according to the Edison Electric Institute. Three of the largest grid operators each set monthly peak-demand records. One surpassed a record that had stood for 20 years.
Demand increases are only the latest factor pushing costs up. Residential electricity bills have grown faster than inflation in 80% of OECD countries since 2010. (See Exhibit 2). The cost pressures on electricity are not confined to a single market structure, generation mix, or regulatory model. They are showing up in liberalized markets, under vertically integrated utilities, on coal-heavy grids and in systems rich in renewables, and in regionally interconnected markets and more isolated ones. The common theme is that costs are now rising at accelerated—and potentially unsustainable—rates.
To slow this acceleration, some companies are moving their facilities to less costly locations. In the UK, a recent study by trade group Make UK found that 9% of manufacturers are shifting production out of the country to contend with high energy costs. In Germany, the share is even higher. A third of industrial manufacturers are moving capacity out of the country, according to an analysis by the German Chamber of Commerce, and 20% of companies across all industries are either moving or considering it. More important, new industrial developments are choosing, when feasible, to locate high-energy-consumption facilities in locations with lower energy costs, slowing growth in the affected countries.
One interpretation is that these increases reflect ongoing shocks from Russia’s 2022 invasion of Ukraine and that costs will ultimately revert to historical norms (as they often do when fuel prices rise and fall). We believe that’s potentially too optimistic. In markets where prices have come off their 2022–2024 peaks, they have settled well above previous levels. Moreover, the factors pushing electricity prices up do not move in line with fuel cycles. We examine the biggest drivers in the next section.
Three Factors Pushing Electricity Costs Upward
Three factors account for most of the affordability impact.
Imbalances Between Supply and Demand. In many markets, supply has not kept pace with demand. For most of the past 15 years, generators primarily focused on replacing infrastructure—retiring higher-cost or higher-emission fossil assets and substituting renewables to service flat loads. Now, demand is growing fast (or is, at least, expected to), and the main task in many markets is addition.
New sources of renewable, gas, and, in some markets nuclear generation are all needed simply to keep pace. Yet backlogs in interconnection queues delay access to some of the cheapest new power sources and force a continued reliance on higher-cost, incumbent resources. At the same time, thinning reserve margins raise the cost of ensuring the system can serve peak demand.
In other markets where demand is falling, the cost of operating the grid remains the same, as a consistent set of fixed costs is now spread among a smaller user base. In the UK, for example, overall electricity demand has been decreasing, which translates to a higher cost burden for individual customers.
Huge Grid Investments. After decades of low or even underinvestment, spending on transmission and distribution upgrades is climbing steeply in major markets, particularly in the US and other advanced economies. (See Exhibit 3.) Utilities are reinforcing aging infrastructure, connecting large new loads such as data centers, interconnecting new generation (including offshore wind), building resilience against more frequent extreme weather, and preparing for the electrification of larger shares of their energy demand. The scale of investment now underway in many markets is unlike anything the industry has seen in decades. Much of that will ultimately cascade to customer bills, either through higher utility payments (in the US) or grid fees (in Europe).
Regulations Designed for Different Market Conditions. Obsolete regulations are the third, and less obvious, cost driver. Though there are variations across markets, many of the rules that govern how costs get recovered from customers and how utilities get incentivized to invest were written based on market conditions that no longer hold: flat demand and falling costs. For example, rules regarding volumetric cost were designed for utilities to recover fixed system costs across a flat (or steadily growing) base of kilowatt-hour sales. These rules are based on overall volume and demand moving roughly in sync, and they don’t distinguish between a kilowatt-hour consumed at 6:00 p.m. in winter and one consumed at 3:00 p.m. on a sweltering summer day.
Today, expanding electrification and data centers push peak demand up, while efficiency gains and more prevalent solar mean that metered volume is decreasing for some utilities (particularly in Europe). Measures are available to relieve peak-demand pressure, like batteries, smart charging, and demand-response solutions. But utilities can’t recover the cost of these measures under existing rules. Instead, they have to spread fixed costs across a shrinking base, pushing up rates.
Rules to incentivize rooftop solar are also increasingly problematic. Net metering gives residential system owners full retail credit for the power they generate. Those rules were effective at catalyzing a nascent market, but now that solar is nearing mass adoption in many markets, it essentially shifts overall grid costs onto customers who don’t have solar. Some countries, such as Belgium and the Netherlands, have moved away from net metering, but it is still prevalent in many other jurisdictions.
A Leading Indicator: The US Market
The US is a notable case study for rising electricity costs for several reasons: it has the fastest load growth in the developed world, and affordability has led to the sharpest political responses to date. Average US electricity prices plateaued in nominal terms through the 2010s and fell in real terms after factoring in inflation. Demand was essentially flat. But as Exhibit 4 shows, the pattern broke in 2021, with nominal prices rising more than 7% annually through mid-2026. (That is an overall average, and some states are seeing a smaller increase.)
This is a significant and threatening shift for utilities, creating business risks in several interconnected areas:
- Investors have taken notice. A review of quarterly earnings calls for the 29 largest publicly traded utilities shows a fourfold increase in mentions of affordability from 2019 to 2026. (See Exhibit 5.)
- The public is seeking someone to blame. Pew Research found that 64% of US consumers cite utility companies wanting to make more money as a major reason for rising costs. That is more than any other factor, including the growth of data centers.
- Politicians are stepping in. State and federal officials are intervening directly in rate cases and exploring other actions such as compensation caps, bans on billing for certain expenses, and income-based rate relief.
- Rating agencies increasingly treat affordability as a financial variable. Some agencies, including Moody’s and Fitch Ratings, cite elevated electricity costs as a potential credit risk for US utilities.
Without significant change, these factors could lead to a doom loop: rising costs trigger more scrutiny and regulatory risk, which leads to credit concerns, in turn raising the cost of capital for utilities and pushing costs even higher.
Another type of doom loop is also a possibility. In this scenario, rising costs weaken the business case for electrifying power demands in areas like heating, even as utilities assess the potential investment required to prepare for increased demand from electrification. Less electrification could lead to higher costs being spread among fewer users, which further increases costs, making electrification even less attractive.
Within the US, one market clearly illustrates the full extent of the affordability problem: the PJM Interconnection. PJM is the largest wholesale power market in the US, serving 67 million people in 13 states and the District of Columbia. It also hosts the densest concentration of data center load in the country in northern Virginia. Rising demand, constrained supply, and an obsolete framework for recovering capex costs all meet in the same place.
The clearest signals have come from PJM’s capacity market, which pays for resources to be available three years in advance of when they are needed and prices them in dollars per megawatt-day (MWD). Recent auctions have repriced steeply, rising from $29 per MWD for 2024–2025 delivery to more than $300 per MWD for 2026–2029. Over the last four capacity market auctions, market charges attributable to data center loads represented 46% of the total, according to PJM’s independent market monitor.
Two features make PJM a leading indicator rather than an outlier. The first is timing. Capacity investments cascade down to retail bills with a lag, so a substantial share of the increase already cleared has yet to show up on customer statements. The second is the political response, which has arrived faster than the bills. State and federal officials have directly challenged the market and governance structure. Market design that was until recently a technical matter is increasingly subject to public debate.
PJM is starting to take action to address these issues, but all of the factors it faces exist elsewhere as well: load growth that outpaces new supply, an interconnection queue that slows the cheapest resources, and a regulatory regime calibrated for a decade of flat costs and growth. Consider another US provider, the Midcontinent Independent System Operator (MISO), which provides power across the midwestern and southern US. The second-largest independent system operator (ISO) in the country, MISO has seen rates rise less than the rate of inflation thus far, primarily because of a vast build-out of renewables and political incentives such as production tax credits. However, demand is rising in the MISO market, and utility capex is set to grow at 11% a year through 2030 (compared to just 6% in PJM). Those costs will likely push electricity prices higher over time. The bottom line? PJM is where many of these factors arrived first. MISO and other ISOs can learn from PJM’s experience, implementing specific measures to avoid some of the price spikes PJM has seen.
Three Sets of Levers to Make Electricity More Affordable
We have identified three sets of levers for regulators, utilities, and policymakers to better control affordability. (See Exhibit 6.)
Near Term: Regulators Can Allocate Costs More Fairly
Regulators (with input from utilities and policymakers) can have the most immediate effect on affordability by better allocating costs. Under current rules, many near-term costs are simply passed straight through to customers without regard for their impact. Regulators can take several administrative steps to rectify this issue.
Align costs to service. Measures such as tiered service, tariffs for large loads, customer segmentation, and low-income protections—more equitably link bills to the cost that the customer imposes on the system. For example, redesigning rate structures corrects for the cost-recovery mismatches described above, such as volumetric rates that cannot price flexibility or net metering that overvalues residential solar production.
Measures such as tiered service, tariffs for large loads, customer segmentation, and low-income protections more equitably link bills to the cost that the customer imposes on the system.
Reallocate costs across groups. Regulators can also balance costs between taxpayers and ratepayers and allocate costs more equitably among rate classes. Germany, for example, moved a renewables surcharge from customer bills to the federal budget in 2022 and capped prices thereafter. The cost did not fall; it was shifted to a broader pool of taxpayers. The UK implemented a similar measure in 2026. France recently reduced its Transmission Tariff Contribution (CTA) from 22% to 15%. (The CTA is a tax based on the delivery of natural gas and electricity and is used to fund pensions for workers in the industry.)
Some countries are opting to give large industrial users discounted energy rates specifically to preserve the domestic industrial footprint and maintain economic competitiveness. That discount is then funded by other ratepayers or taxpayers.
These discussions are already surfacing in rate cases, and they are the most contested of the three levers in this analysis, because they are zero-sum and involve clear winners and losers. It is worth noting that asking ratepayers to fund infrastructure is akin to a regressive tax, while taxpayer-funded infrastructure is more progressive. This is particularly true for transmission and distribution investments, which involve assets with a lifespan of more than 60 years, delivering economic and social benefits across multiple generations.
There is no universally correct approach, but regulators need to be proactive about understanding future needs and make deliberate choices based on their unique circumstances and objectives. The worst solution is to leave current allocations in place simply to maintain the status quo.
Securitize investments to smooth repayments. Bill management tools and securitization can distribute cost spikes over time. For example, a major storm-response program can entail massive expenses. Rather than handing those charges directly to current customers, the costs can be securitized and recouped over many years. This approach changes the timing, not the incidence, of the burden. The customers still pay, just in a more manageable way.
Medium Term: Utilities Can Optimize How They Run the Electrical System
The second set of levers belongs to utilities, which can become more disciplined in how they operate and how they can upgrade their systems to improve efficiency and flexibility in the US. These measures involve both investment from utilities and coordination with regulators, and they take longer to pay off. But under the correct conditions, they can collectively add up to several hundred dollars a year in reduced bills for residential customers, with returns typically coming over several years. (See Exhibit 7.)
Reduce the cost to serve. Many utilities can improve the efficiency of their operations and run their existing systems at lower costs. Available levers include making operations and maintenance (O&M) more efficient, implementing smarter asset utilization, and (for integrated utilities) optimizing fuel costs. All three sit within a utility’s control. In our analysis, increasing the power moved through the existing grid by 10% can reduce customer bills by 7% to 8% and reaching max efficiency can lead to bills that are 10% to 20% lower.
AI can help improve operational efficiency as well. A recent BCG publication about grid productivity found that smarter procurement can reduce costs by up to 15%, and workforce effectiveness programs for employees and contractors can improve productivity by 20% to 30%.
Reduce the cost to build. In our experience, utilities vary widely in their ability to deliver capital projects on time and on budget. Improving their capabilities in this area, along with better capital efficiency, can reduce some of the costs of the ongoing build-out in generation and grid infrastructure.
Reduce what you need to build. With the right regulatory framework, utilities can explicitly weigh the cost of new capex (such as building out the grid or adding new generation capacity) against smarter operations and flexibility solutions that reduce peak demand on the current system. In other words, they can apply a total-expenditure lens when assessing new construction decisions. For example, shifting electricity loads through demand response and storage can smooth demand peaks—and it can often be a smarter approach than simply building more grid or generation capacity. This is particularly relevant for large customers and in wholesale power markets. Flexible pricing schemes for the mass residential market can also reduce peak demand (though they require regulatory approval in many jurisdictions).
Each of these three measures is a utility decision, but the return it ultimately delivers is shaped by the regulatory framework, including the review of the proposed capital expenditures and how quickly factors like O&M savings reset at the next rate case.
Long Term: Policymakers Can Work with Industry to Reshape the Electricity Ecosystem
The levers with the longest timeline for results, but also the biggest potential for transformative change, are design considerations for policymakers. Current market structures were designed for flat demand and declining costs—two conditions that are no longer relevant in most markets. By partnering with electricity ecosystem operators, policymakers can reshape the system to better meet future needs.
Redesign the market to make resources more accessible. The most important step for policymakers is to rethink the regulations that determine how much supply capacity is available, how far ahead of need, and who pays for it. These rules decide whether reserve margins tighten or hold firm and whether interconnection processes deliver inexpensive new generation at the pace rising demand now requires.
Update the generation mix and grid architecture. Next, policymakers can determine which type of generation infrastructure gets built and where it connects. Such choices set the system's exposure to fuel price volatility for a decade or more, since a mix that leans on gas at the margin translates gas price movements directly to power prices. These choices also determine whether consumption can access the cheapest generation or less expensive power is stranded behind a queue.
For example, China designated solar as a strategic industry in 2010 and backed it with sustained credit, land, and tax support, significantly lowering the cost to produce solar power. The country now has roughly half of the world’s solar capacity, according to the International Renewable Energy Agency. The government coupled this strategy with a large-scale, concurrent transmission build-out to deliver cheap solar and wind power to customers, investing about $75 billion a year since 2010.
Manage the growth of large loads. Industrial companies and households determine the business case for electrification, but policymakers determine how much new demand connects to the system, how quickly, and on what terms.
Large load growth, primarily from new data centers coming online, can potentially solve the affordability problem or exacerbate it—a topic we discussed in a recent publication about grid-positive data centers. Structured well, large loads can relieve pressure by spreading fixed system costs across a larger base, assuming that heavy users pay their full and fairly allocated cost of service. Structured poorly—if costs are kept artificially low, deferred, or spread among other ratepayers—they worsen affordability issues. How data-center-driven load increases are resolved, market by market, may be the largest single swing factor for US affordability—and that of most markets worldwide—over the next several years.
How data-center-driven load increases are resolved, market by market, may be the largest single swing factor for affordability over the next several years.
Coordinate across borders. Depending on geography, some governments may opt to join forces with nearby systems, leading to a larger and more resilient ecosystem. For example, Switzerland recently signed an agreement to join the EU’s internal electricity market. As part of this agreement, which won’t be finalized until 2030, policymakers benefit from a common trading platform and grid-operation rules, among other factors. Through this approach, power from hydro, nuclear, wind, and geothermal all supplement each other across borders, leading to a higher share of renewables and a more resilient system than individual countries can create on their own. In a similar move, Scandinavian countries joined forces in the 1990s to create a common organization, Nord Pool. When it was first created in the 1990s, it reduced wholesale energy prices by about 25%.
Solutions to make electricity more affordable are not easy, but they are available. Deliberate, proactive measures by regulators, utilities, and policymakers can slow the spiraling cost growth of electricity around the world, reducing burdens on homes and businesses and making national economies more competitive.
