In April 2021, the United States set a target to create a “carbon pollution-free power sector by 2035”—an important element in the country’s goal of reducing emissions 50 to 52 percent by 2030 and achieving net-zero emissions by 2050.1
McKinsey research has found that significant and early decarbonization of the power sector is a critical factor across many of the pathways to a decarbonized economy. Renewable technologies such as solar and wind are already cost competitive with coal and gas across most US markets, and decarbonizing electricity is essential to enabling decarbonization in other sectors, such as transportation (electric vehicles) and buildings (electric heating).
This article presents a potential “zero-by-35” decarbonization scenario in which each regional power market would reach net-zero greenhouse-gas (GHG) emissions by 2035 without offsets from other sectors. This model also accounts for increased electricity demand from transportation, building-heat electrification, and the industrial sectors that could put the economy on course for a 50 to 52 percent emissions reduction by 2030 and net-zero emissions by 2050. Essentially, this scenario represents a least-cost pathway to decarbonize the power sector while maintaining reliable and resilient electric-grid performance.2
The key concepts and strategies to decarbonize the US power sector featured in this article highlight one potential pathway based on a certain set of inputs. Other viable pathways exist, and new pathways will likely emerge for both the power sector and the broader economy over the next decade and beyond as we learn more and as technology continues to develop. In contrast, a “status quo scenario” illustrates that without new federal emissions-reduction efforts, continual improvements in technology and existing state-level commitments may result in slower and less extensive decarbonization. We estimate that these policies would reduce nationwide power-sector emissions by 59 percent by 2040, relative to 2005 levels.
The power sector’s pivotal role in decarbonization
A key lever for achieving the decarbonization ambitions of the United States is to transition from burning fossil fuels for transportation and heating to using “clean” electricity generated by renewables. To enable this transition, the electric-power sector may need to simultaneously decarbonize while meeting an approximately 40 percent increase in electrical load by 2035 (Exhibit 1). That translates to load growth of 2.0 percent per annum over the next decade, compared with a mere 0.5 percent in the status quo scenario (both stand in contrast to virtually zero load growth over the past 15 years).
The shape of this load will likely shift significantly, with greater movement toward winter-peaking systems, given the accelerated adoption of electric space and water heating. Some local grids in colder climates such as New England have already shifted to winter peaks, and our analysis shows that nearly all markets will likely shift by 2035 as use of heat pumps grows. In the meantime, large markets in warmer climates such as California and Texas will maintain summer peaking but will still see significantly higher winter demand due to increased heating.
The zero-by-2035 scenario anticipates federal emissions-reduction programs that rapidly outpace state-level targets. Given the power sector’s critical role in helping realize these programs, customers, advocates, and regulators are accelerating their expectations for both the speed of decarbonization and end-state targets. Five years ago, few utilities had made commitments to fully decarbonize. Today, 23 states have plans to decarbonize either their power sectors or their entire economies by at least 80 percent by 2050, and many utilities are also establishing goals that are more ambitious than their respective state-level targets.
Building out the required new sources of power generation, the transmission infrastructure to interconnect that generation, and grid-sited flexibility resources to balance intermittency could require up to $2.5 trillion by 2035. The additional cost to upgrade distribution grids, expand and reinforce transmission networks, and invest in downstream applications would increase costs even further. These costs may ultimately be borne by end customers and taxpayers, though the allocations of cost have yet to be determined and require further study.
Ten big moves to help reach net-zero emissions by 2035
Leaders in the electric-power and natural-gas sectors can make strategic decisions today despite uncertainties around state- and federal-level decarbonization pathways. As previously stated, there are multiple viable pathways for reaching net-zero GHG emissions by 2035 (see sidebar “An alternative to 100 percent power decarbonization”). The following list aims to provide project developers and operators, utilities, technology companies, governments, and others with a layer of specificity that may be missing from the current conversation around power-sector decarbonization. This additional specificity could help stakeholders further close the gap on uncertainties around deploying capital, scaling technologies, and mitigating risk.
- Unlock the next S-curve for wind and solar through improved permitting and siting and by scaling supply chains. In this scenario, new solar and onshore and offshore wind would represent 60 percent of total capacity by 2035, requiring both industries to increase the rate of annual deployment roughly sevenfold to deploy 1,500 gigawatts (GW) of renewable capacity over the next 15 years. This could require more skilled labor, expanded supply-chain capacity, and new maritime port facilities for offshore wind. And although the direct land requirements for renewables represent less than 1 percent of total land area in the continental United States, deploying economic projects within that footprint is increasingly challenging due to a combination of limited and fragmented land use and the difficulty of obtaining right-of-way to build connecting transmission.3 New York’s Office of Renewable Energy Siting, established to dramatically accelerate deployment through standardized permitting and other improvements, is an early example of one way to tackle these challenges, although scaled-up successes across the country will require a much more comprehensive effort.4
- Expand interstate transmission corridors. Regions with high renewable penetration already face increasing transmission congestion, which has led to prohibitive interconnection costs and caused many renewable projects to drop out of the development pipeline. In fact, since 2014 the United States has developed only three GW of interregional transmission, while China has developed approximately 260 GW.5 Looking ahead, these transmission constraints will also increase reliance on local generation even when less economic. For example, this model shows that expanded transmission linkages between New England and Canada could enable the United States to import low-cost hydroelectric power, offsetting the construction of 15 GW of higher-cost wind and solar. Federal and state agencies are working on solutions to achieve the scale of this scenario through initiatives such as the recent federal infrastructure deal, which includes $73 billion in funding for clean-energy transmission and new tools for federal agencies to accelerate interstate projects.6
- Expand intraday flexibility across the grid. Generation in a decarbonized power sector will come largely from intermittent renewable sources. Matching power supply to demand on an hourly basis will require deployment of flexibility resources to complement low-cost renewable energy (Exhibit 2). More than 300 GW of short-duration response is needed to meet intraday demand. Grid-scale storage—including, but not limited to, lithium-ion batteries—will integrate renewables while also increasing the use of the transmission infrastructure. Fortunately, there was more than 200 GW of battery storage in US interconnection queues as of the end of 2020, signaling a rapidly growing market.7 Thoughtful deployment of battery storage on the distribution system could not only help manage large swings in load from electrification but also strengthen the resiliency and reliability of the aging distribution-network infrastructure. In addition, demand levers will become increasingly important, including managed charging from transport electrification and thermal storage through smart building-energy management for space and water heating, both of which are already beginning to gain traction.8 Finally, commercial and industrial demand response could play a key role, with dispatchable loads such as dual-fuel industrial heating, high-latency data centers, off-peak water pumping, and flexible hydrogen electrolysis providing significant balancing potential with little to no financial (or physical) impact on customers.
- Accelerate coal retirement. The zero-by-2035 scenario would lead to a rapid retirement of existing coal baseload generation (more than 245 GW in the next 15 years) due to a combination of emissions constraints and economic inefficiency. Recent years have seen an uptick in retirement announcements. Current plans would cut capacity by 45 percent by 2035, relative to a 2015 baseline (versus prepandemic plans to cut 30 percent). However, many of the remaining plants are part of regulated utilities’ rate base with significant value remaining on balance sheets, and a viable solution to retire the plants must account for that value. Solutions developed so far include securitization of the plant value on customer power bills, accelerated retirements, and asset write-downs; securitization creates incentives for utilities to redeploy capital toward renewables. For example, in 2020 the Michigan Public Service Commission approved Consumers Energy’s proposal to retire the D. E. Karn coal plant by issuing $688 million in securitized bonds. This action is expected to save customers $124 million and unlock capital for new low-carbon investments.9 Holistic coal-retirement plans would also account for transitioning displaced coal employees.
- Keep existing nuclear facilities online. We estimate that more than 20 GW of nuclear capacity will retire by 2035 based on both announced retirements and current license expirations. That said, this modeling shows the economic, emissions, and reliability benefits of keeping the remaining 60 GW online. Many nuclear plants are struggling economically today due to low power prices and high fixed costs.10 Discussions are under way at the state and federal levels to provide additional financial support to keep some plants online. For example, Illinois recently passed new financial supports to keep the Byron and Dresden generating stations in operation following announcements of their imminent closure. The least-cost analysis demonstrates the overall system benefits of keeping such plants open, while acknowledging that the discussion around nuclear power is often fraught.
- Deploy dispatchable zero-carbon generation, including solving the role of gas. Gas-generation capacity will likely continue to grow under the zero-by-2035 scenario. Such growth could both provide seasonal flexibility and bridge the gap during periods of low regional renewable output, with approximately 590 GW online by 2035 versus 414 GW today (Exhibit 3). Given the net-zero emissions trajectory, however, these plants could not run as they do today. Thus, a mix of zero- or low-carbon fuels, such as hydrogen, biomethane, renewable natural gas, and ammonia, will likely be needed to provide peaking capacity to bridge extreme weather events. In parallel, plants that run at higher utilization levels to balance structural or seasonal mismatches will need carbon-capture retrofits. Furthermore, combining bioenergy with carbon capture and storage (BECCS) creates a negative-emissions asset that, while more expensive to operate, could be an important contributor to solving the net-zero trajectory for power.
According to the cost-optimal scenario, a mix of all three of these options, deployed appropriately, is likely. On this point, California plans to build gas peaking plants to address recent resource adequacy issues. Alternatively, long-duration storage or small modular nuclear reactors (SMRs) could play this role, though scaling these technologies to meet a 2035 net-zero timeline may prove more challenging than leveraging the existing gas infrastructure and generally proven technologies.
- Simplify behind-the-meter generation and expand its use. Distributed solar and storage, electrification of home appliances, and building efficiency upgrades likely need to scale significantly to achieve decarbonization ambitions. However, solar adoption faces several challenges, including interconnection and permitting complexity. In fact, the United States had installed three million residential solar systems by 2021 (approximately 2.4 percent household penetration), while Germany had around two million (6.0 percent household penetration).11 Behind-the-meter solutions can also reduce the need for transmission upgrades, making them less susceptible to the challenges and risks associated with large-scale renewable projects. And because individuals and businesses can directly observe them, they increase people’s sense of participation in the energy transition.12 These solutions will likely require significant commitments to unlock financing, scale the workforce, and structure the correct incentives at the state level.
- Strengthen grid resiliency. Over the past two years, grid operators have grappled with large-scale outages due to extreme temperatures, some of the largest wildfires in modern history, and the most active hurricane season on record. The widespread disruption to power and gas service in Texas in February of this year and recent sustained power outages in New Orleans following Hurricane Ida are two of the highest-profile examples. Extreme weather events as a result of climate change will likely continue to occur, while a larger share of economic activity will become reliant on the electric grid. This means electric grids can be strengthened, whether through new forecasting capabilities, stronger electrical design standards, or significantly stronger cybersecurity. Notable examples of such moves include Con Edison’s $1 billion in additional expenditures since 2012,13 and Florida Power & Light’s ongoing grid-resilience programs.14
- Restructure market and regulatory mechanisms. Driving significant decarbonization may require states, regional power markets, and the federal government to consider several new tools. First, regulatory constraints on carbon emissions could help to achieve the desired pace of emissions reduction. Second, government support could reduce technology costs (such as for R&D and deployment capital), spur adoption (through accelerated permitting), and ensure the core supporting infrastructure is in place. Third, targeted programs such as the Low-Income Home Energy Assistance Program (LIHEAP) can provide targeted support for disadvantaged households.15 Fourth, a move from volumetric to peak electric pricing, already in place for many large commercial and industrial customers, could spur the creation of demand response programs that reduce the need for firm generation (several technologically proven offerings can be rapidly scaled, from smart vehicle chargers to water heaters). Fifth, energy markets may need to identify a new pricing mechanism that adequately compensates dispatchable capacity in a power system in which the marginal cost of electricity frequently approaches zero. And finally, performance-based regulatory frameworks, which aim to align business incentives with customer-service goals, can help provide road maps for utilities adopting renewables and other new technologies. As these changes occur, tension could continue or increase between individual states and independent system operators or regional transmission organizations that operate in multiple-state markets.
- Build a national transmission network for hydrogen and captured carbon. New infrastructure to deploy hydrogen fuels and capture carbon is critical—both to enable dispatchable zero-carbon generation and to enable low-carbon alternatives to electrification in other sectors, particularly those in which electrification is challenged (such as high-temperature industrial heat or fuel density in clean transport) or in which natural gas can be replaced as a feedstock in industrial process (such as cement and fertilizer).16 In the United States, for example, the presence of low-cost natural gas and geological carbon storage means that the economics of low-carbon, methane-based hydrogen, or “blue hydrogen” (through steam-methane reforming or autothermal reforming), could be favorable in the near term, as compared with green electrolysis in much of the rest of the world. According to this analysis, green hydrogen begins to “win” in economically driven new builds by 2040 and could continue to take advantage of established pipeline networks while also creating demand flexibility to enable higher levels of intermittent renewable generation (Exhibit 4). In Europe, active discussion of an expansive hydrogen network is supporting players across the value chain in making strategic moves to scale up their investments.17
These points illustrate what it might take for the United States to achieve a carbon pollution–free power sector by 2035. The scale of capital deployment, system transformation, and policy evolution is large. We hope that this article will spur discussion among market participants on what this level of decarbonization may require and on the business opportunities it presents.
