Decoding the cost dilemma: How can electric companies navigate a shifting landscape?

The math

We’ll start once again as we did in 2013 with the basic equation:

The answer to the equation refers to the cost per kWh sold, not necessarily the price charged to customers.⁵ A slightly expanded version of the equation is described in figure 1.

Understanding the factors influencing the variables

The next step is to identify those factors that can significantly influence the three variables in the equation—capital costs, operations costs, and kWh consumed.

We propose the following factors as those most likely to impact the variables in our equation through the rest of this decade (figure 2).

The last decade (2013–2022)

Over the last 10 years (2013–2022), US annual electricity consumption continued to grow slowly (figure 3). While it fluctuated from year to year due to weather and economic trends, including the COVID-19 pandemic-driven downturn, it grew overall at a compound annual growth rate (CAGR) of about 1% per year, as it has for the past 20 years.⁶

Meanwhile, utility industry capital expenditures (capex) continued to rise, totaling more than US$1 trillion as companies upgraded, replaced, and hardened infrastructure; added renewable and natural gas–fired generation capacity; deployed smart grid technologies; and more (figure 4).⁷

But the math dilemma was held at bay largely because generation fuel costs fell from the previous decade (figure 5), primarily due to the shale gas revolution. In this environment of lower natural gas costs, gas-fired generation’s share of the US generation mix rose from 28% in 2013 to 40% in 2022.⁸ Lower interest rates also helped keep costs down. As these cost savings were passed through to customers, they left headroom for increasing capital expenditures.⁹

The current decade

Over 2021–2022, natural gas prices rose sharply as supplies were constrained due to lower output and the Russian invasion of Ukraine. In addition, pandemic-related inflation, supply chain constraints, and extreme weather sharply boosted overall costs, resulting in a record US$17.3 billion in utility requested rate increases (figure 6).¹⁰

Looking ahead to 2030, what can we expect in terms of the direction and magnitude of the changes in the factors we identified in figure 2?

The numerator: Capital costs will likely continue to rise

Capex for the largest group of investor-owned utilities (IOUs) rose at nearly a 6% CAGR for the decade ending in 2022.¹¹ In projections for 2023–2025, the increases appear to be accelerating,¹² likely due to inflation, looming clean energy target dates, and plans to harness the clean energy funding and tax credits provided in the recent Infrastructure Investment and Jobs Act (IIJA) and Inflation Reduction Act (IRA). Our analysis indicates that over the next decade, capex could grow at a CAGR of 5% to 8% or more, amounting to US$1.5 trillion to US$1.8 trillion.¹³ The following factors can significantly impact those expenditures, either adding to capital spending or offsetting it:

1. Investment in new generation: In line with the capex growth noted above, we expect electric power companies will likely invest roughly US$370 billion to US$615 billion in generation capacity from 2023 to 2030.¹⁴ They plan to use these investments to help replace retiring plants, deploy cleaner generation sources, and address reliability requirements.¹⁵ Renewables and battery storage are expected to dominate capacity additions, progressing from a starting point of about 82% of new capacity in 2023, according to the US Energy Information Administration (EIA).¹⁶ And, for the first time, large-scale solar installations will likely exceed wind, accounting for more than half of new capacity in 2023. Battery storage will likely place second, as systems are increasingly installed to back up variable solar and wind energy.¹⁷ And the Biden administration is aiming for 30 GW of offshore wind capacity by 2030, from the current 42 MW.¹⁸ The IRA is already helping to defray some of these investment costs (see “State and federal incentives/subsidies” below).¹⁹

2. Investment in new/upgraded transmission (infrastructure and control systems): Our analysis suggests the industry could invest about US$260 billion to US$350 billion to upgrade, harden, replace, and build new transmission infrastructure between 2023 and 2030.²⁰ Studies indicate the need to expand US transmission systems by 60% by 2030, especially to support growing renewable energy deployment and electrification.²¹ Yet, new transmission projects are often delayed by interstate permitting challenges. Grid-interconnection queues grew 40% year over year in 2022—to more than 1,350 GW of generation and 680 GW of storage—exceeding the capacity of the entire US power plant fleet.²² Over 95% of the queue is zero-carbon energy, particularly solar and battery storage.²³ And that growth is likely to accelerate as companies seek to harness IRA incentives and meet decarbonization goals.

Transmission congestion prevents lower-cost energy from reaching consumers and cost an estimated US$13.3 billion in 2021.²⁴ In addition, most transmission lines and transformers are over 25 years old, which is leading to higher outage time and costs.²⁵ Expanding transmission to connect assets within a larger geographic footprint can increase reliability and reduce costs. About 7% (or US$18 billion to US$25 billion) of transmission investment is typically spent on advanced technologies such as sensors, artificial intelligence (AI), and other remote monitoring and control technologies.²⁶ The IIJA includes a US$2.5 billion Transmission Facilitation Program to help enable large-scale transmission deployment.²⁷

3. Investment in new/upgraded distribution (infrastructure and control systems): Our analysis indicates that electric company investment in the distribution system over 2023–2030 will likely range from US$420 billion to US$580 billion.²⁸ This includes new equipment and replacement, upgrades, and hardening of existing equipment against extreme weather.²⁹ Around 12% of investments, or US$50–70 billion, is typically spent to deploy advanced technologies that help integrate renewables and distributed energy resources (DERs), such as rooftop solar, electric vehicles, and battery storage.³⁰ These include Advanced Metering Infrastructure, demand response, and distribution management technologies.³¹ Integrating more DERs could increase grid flexibility and help reduce the amount of new generation and transmission required.

Electric companies are typically spending not only on hardening infrastructure against increasingly severe climate events, but also on recovering from them. An estimated US$12.4 billion of weather-related debt was issued in 2022 alone for utility disaster recovery, compared to US$7 billion total from 2002 to 2021.³² Utilities are also investing in sensors, high-definition cameras, weather stations, and drones for wildfire prevention and other infrastructure inspections.³³ The cost of mitigating and adapting infrastructure to climate change can appear high, but it could be billions lower than the cost of inaction, according to a Deloitte analysis.³⁴ IIJA funding could support some distribution system investment, including US$3 billion for the smart grid investment grant program; US$5 billion for grid resilience projects; and US$5 billion for grid reliability and resilience research, development, and deployment.³⁵

4. Energy storage investment: Our estimates suggest that electric companies will likely invest US$48–70 billion in utility-scale energy storage over 2023–2030, funding about 60–90 GW of mostly lithium-ion battery storage.³⁶ Battery storage’s 80% cost decline from 2013 to 2022³⁷ is driving growth, combined with its capability to solve multiple challenges, from renewable variability to high peak demand.³⁸ States have increasingly added storage carve-outs to their Renewable Portfolio Standards.³⁹ And the IRA created a separate tax credit for storage projects, whether stand-alone or colocated with generation.⁴⁰ The IIJA provides US$8.5 billion for battery and critical minerals manufacturing, recycling, processing, and innovation to help develop a US battery supply chain.⁴¹ It also allocates more than US$9 billion for clean hydrogen hubs and hundreds of millions to support innovation in other types of long-duration energy storage.⁴² Many utilities are also investing in systems to integrate increasing amounts of customer-owned storage.

5. EV-related investments: Members of the IOU trade association, Edison Electric Institute (EEI), have invested more than US$4 billion in transportation electrification programs.⁴³ IOUs are investing primarily in EV-charging infrastructure as well as customer education and outreach programs. In addition, more than 60 investor-owned, public power, and cooperative electric companies formed the National Electric Highway Coalition (NEHC) in 2021 and committed to deploying more than 4,500 EV fast charging ports along major US travel corridors.⁴⁴ EEI predicts the US light-duty EV fleet will grow from about 4 million vehicles in 2023 to 26.4 million by 2030, and that powering these vehicles will require about 140,000 DC fast chargers and a total of 12.9 million charge ports, a roughly ten-fold increase.⁴⁵ Building this infrastructure could cost more than US$40 billion.⁴⁶ Public and private stakeholders have committed billions to the effort already, including through the IIJA, but EEI projects a shortfall of nearly 70% in the number of fast charging ports needed in 2030, given the currently announced levels of funding.⁴⁷

6. Investment in cyber and physical security: US electric companies collectively spend billions of dollars annually on cyber and physical defense, and those expenditures could rise as requirements increase. Spending is generally for securing assets, systems, and supply chains. One benchmark study found that utilities spent an average of 8% of their IT budgets on cybersecurity in 2022.⁴⁸ Most utilities are already incorporating the minimum cybersecurity requirements that the Biden administration outlines in its recently released national cybersecurity strategy for critical sectors.⁴⁹ But the North American Electric Reliability Corporation Critical Infrastructure Protection (NERC-CIP) standards that they also adhere to do not cover the distribution system, and the growing wave of DERs will need to be protected.⁵⁰ To proactively secure the interconnected hardware and software systems they’re deploying to manage the smarter, cleaner grid of the future, they may need additional funding avenues.⁵¹

7. Changes in cost of capital/interest rates: The industry will require a significant amount of capital to fund its investments over the decade, and much of it could be through debt financing. Interest rates have been rising in 2022–2023 as the Federal Reserve attempts to address postpandemic inflation (figure 7). And while it’s difficult to project where they’re headed over the next seven to eight years, it seems unlikely that rates will be lower than the average 2.1% experienced in the last decade (2013–2022); they could even settle in significantly above that level.⁵²

8. State and federal incentives/subsidies: While they can’t cover the entire US$1.5–1.8 trillion investment expected by 2030, the IIJA, IRA, and CHIPS and Science Act are, in some cases, already helping to reduce costs of electric company investments through tax credits; grants and loans; or research, development, and demonstration (RD&D) of new technologies (see the sidebar, “Recent legislation could create more than US$500 billion in clean energy research, funding, and incentives”).⁵³ Several utility chief executive officers (CEOs) said the IRA reduces the cost of new energy projects, resulting in savings that could temper rate increases and enable even more investment.⁵⁴ In fact, over the first seven months after IRA enactment, electric utilities announced more than US$4.4 billion in rate reductions for over 24 million customers due to IRA tax credits.⁵⁵ Companies also announced 96 GW of new clean power capacity, which would exceed the last five years of installations (2017–2022) if completed.⁵⁶ In addition, smaller utilities, and nonprofits without tax liability, such as municipal and cooperative utilities, can potentially harness the tax credits due to new direct pay and transferability options.

The numerator: Operations costs

1. Changes in fuel costs: Natural gas fueled about 40% of US electricity generation in 2022, and gas-peaker plants, often last to be dispatched, frequently set marginal electricity prices.⁶⁰ Abundant shale gas helped keep US gas and electricity prices low enough to create headroom for rising capex over the last 10–15 years. From 2013 to 2022, natural gas delivered to electric utilities averaged US$4.01 per million British thermal units (MMBtu).⁶¹ But the equation changed when weather effects, fuel switching, supply bottlenecks, and the Russian invasion of Ukraine curtailed natural gas supplies in 2021–2022, boosting prices to an average of US$7.22 in 2022 (figure 8).⁶² Spiking gas prices helped ignite record-high electricity rates, leading to affordability concerns.⁶³ And some regulators became more hesitant to approve cost recovery for utility capital spending programs.⁶⁴

Natural gas prices fell again in early 2023 and are expected to average US$3.41 per MMBtu for 2023–2030.⁶⁵ But electric company planners expect market uncertainty and anticipate that volatility could return with geopolitical, weather, or other developments.⁶⁶

Renewable energy accounted for 22% of US generation in 2022 and is expected to gain two to five percentage points per year, reaching nearly 50% by 2030.⁶⁷ Theoretically, this could reduce vulnerability to fuel price volatility. But as the wind and solar generation share grows, variability will increase, and until more long-duration storage is available, gas-fired generation will likely continue to play a critical role and impact prices.⁶⁸

2. Changes in Power Purchase Agreement (PPA) prices: Some utilities purchase renewable energy through PPAs rather than owning the assets. While wind and solar project costs declined sharply for more than decade until 2021 and typically compete favorably with other generation sources, PPA offer prices have trended upward over the past two years.⁶⁹ This is due to strong demand; interconnection backlogs; supply chain congestion; rising capital costs; and uncertainty over evolving federal, state, and regional policies and regulations.⁷⁰

3. Other operations and maintenance (O&M) costs: The US utility industry spends an average of US$14.6 billion on distribution system O&M annually.⁷¹ Identifying additional O&M savings could help provide headroom to increase capital spending without raising rates. But many costs rose recently due to factors ranging from supply chain constraints to rising labor costs and overall inflation. For example, the effective hourly labor cost for transmission and distribution field workers may be 22% higher in 2022 than it was in 2020.⁷² Some electric companies have reported increased spending on reliability, safety, training and vegetation maintenance, labor, and materials.⁷³ But after nearly two years of volatile and rising costs, many companies are trying to factor these uncertainties into their planning and identify additional savings. Many are pursuing operational efficiencies using technologies such as AI and cloud to improve work management, supply chain, procurement, and vendor management. Some see their grid modernization investments already paying off in fewer service calls. But the expected growth of DERs means companies will likely have far more devices to manage, which could add costs. They’ll likely continue to find ways to cut costs, but it could remain challenging, especially given projections for continued labor constraints due largely to retirements.⁷⁴

The denominator: kWh consumed

1. New sources of electricity demand: Despite ups and downs due to economic fluctuations such as the pandemic, US electricity demand⁷⁵continued to grow at an average rate of 1% per year, as it has over the last 20 years (figure 3). While the economy typically grows at a faster rate, energy efficiency gains largely offset electricity demand growth over time for the country as a whole. Areas that are adding population, such as some states in the South and West,⁷⁶ may experience absolute demand growth, while areas that are losing population would generally only experience growth by other means, such as growing electrification.

Rising electricity demand from growing electrification of end uses across the US economy may have the greatest potential to “change the math” for electric companies and the industry as a whole. Electrification is expected to progress most rapidly in the transportation sector with growing adoption of electric vehicles.⁷⁷ In the building sector, electric heat pumps and other electric appliances could increasingly replace fossil fuel burning systems. And in the industrial sector, electric heating technologies can do the work of gas and oil burners in many cases.⁷⁸ Additional kWh sales from electrification could potentially boost the denominator and help offset rising costs in the numerator. Models such as the one cited in figure 9 suggest the fastest growth will be in the transport sector before 2030, though demand growth is cumulative, so it will likely build most significantly across sectors over time.

The National Renewable Energy Laboratory’s (NREL) Electrification Futures Study modeled US electricity demand increasing at a CAGR of 0.4% to 1.3% in three different scenarios from 2023 to 2030 (figure 9). These scenarios were modeled before recent legislation such as the IIJA and IRA, whose funding and incentives for the purchase of EVs, electric heat pumps, and more could boost growth rates closer to the 1.3% scenario or higher. Electrification-driven demand growth will likely vary significantly by geography, potentially advancing faster in states like California, which actively designs policies to promote it.⁷⁹ For example, Southern California Edison forecasts electricity usage growing 60% by 2045 in its territory and has projected 2% annual growth in electricity demand from 2023 to 2035 due to recent state legislation and building codes.⁸⁰

As electrification potentially accelerates beyond 2030, especially in the transportation sector, NREL’s high-growth scenario illustrated a 2% CAGR from 2031 to 2050 (figure 9). Again, growth could rise to this level or higher, given the lasting boost that may be provided by IIJA, IRA, and CHIPS Act investments. After the IRA passed, Princeton climate modelers estimated that electricity supply “must more than double by 2050” to accommodate all the new EVs, heat pumps, industrial electrification, and more that would be incentivized.⁸¹ This would imply a 2.5% CAGR until 2050. In addition, the CEOs of two large electric utilities have suggested electricity demand will triple by 2050, which would require more than a 4% CAGR over 27 years.⁸²

2. Changes in customer attitudes/behavior: While electrification could potentially increase demand for electricity from utilities, other factors could reduce it. Key examples include technological advances in energy efficiency and customer or third-party generation and storage of electricity, especially in states where regulations have not decoupled utility sales from earnings.

Electricity sales have long been impacted by customer adoption of energy-efficient devices and technologies, such as LED lighting and building or home energy management systems. Our analysis shows that energy efficiency measures and advanced technologies could shave 580–770 billion kWh from annual US electricity consumption by 2030.⁸³ At the same time, self-generation, often from renewable energy, could reduce demand from utilities by 1,126 billion kWh over 2023–2030.⁸⁴ While customer or third party–owned solar installations currently generate just a fraction of overall electricity,⁸⁵ it’s growing rapidly. And the recent extension and expansion of federal tax credits for solar and energy storage, coupled with rising retail electricity prices, could accelerate growth further.

3. Changes in weather: Climate change has contributed to higher average temperatures in recent years.⁸⁶ Heat wave frequency has tripled since the 1960s and the duration and intensity of heat waves have boosted average temperatures in some areas (figure 10).⁸⁷One study suggests that US summers could last nearly six months by the year 2100 if greenhouse gas emissions continue at the current rate.⁸⁸ With projections for more extreme weather, electricity demand will likely increase.⁸⁹ Milder winters could save more fossil fuels than electricity in the near term since about 56% of homes are heated with natural gas, oil, or propane, while the 40% that use electricity are located largely in Southern states where heating demand is lower.⁹⁰

4. Changes in the economy: While electricity demand may continue to rise marginally with economic growth and fall during downturns, the correlation has declined over time (figure 11). This is largely due to energy efficiency gains, which can offset demand. A notable economic trend to watch is US reshoring of manufacturing in an effort to build new industries and secure pandemic-disrupted supply chains.⁹¹ This trend could be reinforced by IRA provisions that allow bonus tax credits, or “adders,” for clean energy projects that meet domestic content requirements.⁹² Manufacturing growth can increase energy demand, including electricity. The IRA prompted announcements of 47 new or expanded grid-scale clean energy manufacturing facilities in less than nine months after enactment.⁹³ And from August through December 2022, the CHIPS and Science Act spurred a US$200 billion investment in US semiconductor manufacturing.⁹⁴

The math at work

Figure 12 suggests the likely implications of the factors on the variables in the equation. Based on this research, we can draw general conclusions about which factors could most significantly impact the “math” of electric companies or the sector as a whole.

IOUs will seek to invest the capital required to provide safe, reliable, and increasingly clean electricity at affordable rates, as is their regulatory mandate. While the capital required has been rising, the amount that regulated utilities can invest is typically limited by the customer affordability mandate, i.e., if the customer rate increases required to fund the investments are deemed too high, regulators may hesitate to approve utility cost recovery for those investments.

Beyond that, among the factors most likely to either constrain spending or provide headroom for additional investments, depending on their direction, are changes in interest rates, fuel costs, and government policy and incentives. In the denominator, “new sources of demand” is an important indicator to watch, as well as changes in the economy. In addition, geography matters. Since trends such as weather patterns, generation mix, regulatory structures, and economic growth differ across states and regions, each company can evaluate alternatives in light of its own “math.” And there are many levers a company can pull to help improve its math (see sidebar, “Improving the math”).

Conclusion

As our analysis indicated, the largest IOUs could collectively spend upwards of US$1.8 trillion in the next seven years to maintain, operate, and decarbonize the US electric grid. That spending could help them “keep the lights on” and stay on track to meet decarbonization goals. But that’s not a given. If natural gas costs, interest rates, inflation or other factors rise too sharply, or if other trends reduce revenue growth, further spending could become untenable, since it could require significant customer rate increases. On the flip side, new government funding or incentives, additional kWh sales through electrification, or other developments could enable larger investments and a faster transition.  

The clean energy transition is expected to eventually improve this equation. Fuel costs across the industry could decline substantially once the grid is run primarily on renewable energy and storage. And electricity demand may increase considerably as electrification grows. But the full effects of these changes could still be a long way off and the transition requires funding now.

Electric companies can turn to strategies such as those listed above to help improve their own math. Within the broader electric power sector, changes such as permitting reform for transmission projects; new regulatory structures; and additional sources of federal government funding, incentives, and partnerships could also help solve the energy companies’ cost dilemma and advance the energy transition.