If the United States is to decarbonize its economy, the power sector has a critical role to play. It accounts for 27 percent of US greenhouse-gas emissions 1 and plays a foundational role in decarbonizing other sectors, such as transportation and industry, by shifting them away from fossil fuels.
Decarbonizing the US economy, however, is complicated by the fact that the US electric power sector is highly regionalized, with each market having its own governance and structures. Approximately 65 percent of the country’s electric power is bought and sold in competitive markets run by seven independent system operators (ISOs).2 The ISOs design and implement competitive market structures in 37 states plus the District of Columbia; the rest are primarily managed by regulated, vertically integrated utilities.3 Therefore, with little federal action on decarbonization, the states and ISOs are the ones setting the direction.
As of September 2020, 22 states plus DC have set targets to fully or mostly decarbonize their power systems over the next ten to 30 years.4 Four more have set targets to reduce at least one-quarter of their emissions; we call these 26 states “policy driven.” The other 24, which account for 55 percent (in total megawatt-hours in 2019) of US electric power generation, have no or limited targets;5 we call these states “cost driven.”
In this article, we explore the differences in how the policy-driven and cost-driven market types are likely to evolve from now to 2050 under certain policies—and what their evolution means for the overall trajectory of the US power system.6
In a forthcoming article, we will discuss how this trajectory could evolve under a Biden administration, given the President-elect’s Build Back Better Plan and its commitment to 100 percent clean energy in the US by 2035.
Defining the markets
Each market is classified as either policy driven or cost driven based on the collective policies of its constituent states (Exhibit 1). “Policy driven” includes the New York Independent System Operator (NYISO), the California Independent System Operator (CAISO), Independent System Operator–New England (ISO–NE), and parts of the Western Electricity Coordinating Council (WECC). “Cost driven” includes the Midcontinent Independent System Operator (MISO), the Electric Reliability Council of Texas (ERCOT), the Southwest Power Pool (SPP), the Southeast Reliability Corporation (SERC), and the Florida Reliability Coordinating Council (FRCC). The country’s largest market, PJM—which covers much of the mid-Atlantic region—is nearly evenly split between decarbonization and cost driven, so we have not classified it. Strictly speaking, these markets are a mix of integrated competitive ISO markets and non-ISO regions that are really a grouping of vertically integrated utilities. For the purposes of this article, we refer to them all as “markets,” although we still capture the differing policies of the states within those markets.
We characterize most of the country’s biggest markets, including MISO and SPP, as cost driven. We project, therefore, that the US power sector will reduce its overall carbon emissions by 17 percent by 2030 and by 36 percent by 2050, a slower pace than expected for policy-driven markets such as California, New England, and New York, which are seeking to reduce carbon emissions by 80 to 100 percent by 2050.
We model a scenario in which markets meet current economy-wide decarbonization policies across states. We project that electrification of vehicle transport and building heating will increase demand for electricity; both are required to meet decarbonization targets. We then model the evolution of the electric grid over time to meet this demand. Renewables are the largest-growing source of generation driven by both state-level clean-power policies and by continued improvements in the cost and performance of solar and wind power (Exhibit 2).
The potential impact of carbon pricing on decarbonization
Policy can dramatically influence the nature of power systems—their physical makeup, the way they run, and the amount of carbon they emit. Perhaps most interesting is the implicit disruption that changes in policy could bring. If markets such as MISO, PJM, and SPP were to adopt deep decarbonization policies—spurred by either state or federal action beyond anything we see today—the changes to their systems and to how value accrues to operators in those systems could be enormous.
We examined the effects of different levels of carbon pricing—one of many potential policy mechanisms to achieve decarbonization (exhibit). We simulated the entire US power system with different levels of carbon prices ranging from $25 per ton to $200 per ton introduced from 2025 to 2030. For context, the carbon price in the European Union carbon-allowance system was around $27 per ton in 2019. 1
We estimate the US power system would decarbonize by 36 percent by 2050 under today’s policies. A carbon price of $50 per ton would increase that level to 55 percent and $100 per ton would increase decarbonization to 75 percent. To achieve levels close to 90 percent would take, by our estimates, a carbon price of $200 per ton. This analysis offers a sense of the cost and extent of policy shifts that would be required to bring the full country onto the “decarbonization pathway.”
Unsurprisingly, we see very different rates of decarbonization over time across the market archetypes (Exhibit 3). Cost-driven markets do show some reductions, primarily from the retirement of coal plants and modest growth of increasingly cost-competitive renewable power (particularly in SPP states). Our additional analysis assesses how significantly the pace of US-wide decarbonization would vary with changes in policy (see sidebar, “The potential impact of carbon pricing on decarbonization”).
How the market types will differ over time
The trajectories of policy-driven and cost-driven markets differ significantly over the next 30 years. Efforts to reduce emissions will not only accelerate power demand but also influence the mix of power generation in policy-driven markets.
Demand for power grows twice as fast in policy-driven markets
Over the next two decades, the biggest factor that will increase demand for power is the extent to which electric vehicles (EVs) and electric heating in buildings are adopted as markets push to meet decarbonization goals. As long as the electric grid gets its electricity from enough clean sources, EVs and electric heat pumps emit less carbon than their conventional combustion-engine and gas-boiler counterparts. Since driving vehicles and heating buildings together account for about 40 percent of US carbon emissions, effective decarbonization requires electrification.7
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To meet emissions-reduction targets in policy-driven markets, power demand will increase by an average of 35 percent by 2040, according to our analysis; California and New York could see increases of 41 and 43 percent, respectively (Exhibit 4). After 2040, demand could rise further due to larger-scale production of hydrogen for transport, industrial production, and power system balancing. In cost-driven markets, by contrast, we expect more modest electrification, with growth of 15 percent by 2040. The exception to these trends is ERCOT (the ISO serving most of Texas), a cost-driven market where we expect demand for electrification to grow as population and GDP growth outstrip the rest of the United States.
These levels of electrification are far from assured and would require coordination across sectors. But this analysis serves to illustrate the difference in dynamics across markets.
Policy-driven markets build more zero-carbon power—sooner
While both types of markets will see at least some shift in generation toward zero-carbon sources—including nuclear power, wind, solar, and other renewables—they diverge in how far and how fast they shift to these sources. Geography matters. Some markets, such as NYISO, have promising access to offshore wind; the Southeast and California are inherently attractive for solar generation.
Contrasting ISO–NE, a policy-driven market, and MISO, a cost-driven one, highlights the differences between market types (Exhibit 5). In ISO–NE, while some gas generation will remain by 2050 (12 percent), the overall mix will move quickly to renewables (77 percent).
In MISO, on the other hand, gas will displace coal and grow quickly over the next 20 years. Renewables will not be as cost-effective as existing gas plants in MISO until the 2030s; solar capacity installations would bring renewables to 24 percent of MISO’s generation mix by 2050 (a point ISO–NE will reach more than 20 years earlier), with gas making up 72 percent.
ISO–NE’s installed capacity will grow much more quickly than the amount of power generated. This is because increasing amounts of its power will come from renewables, which produce relatively low amounts of power per megawatt of installed capacity. Furthermore, the gas plants in ISO–NE will run less often over time to meet the region’s limitations on carbon emissions. The combined result will be a power system with a much lower level of utilization.
Gas expands substantially in cost-driven markets but acts as a bridge fuel in policy-driven markets
In cost-driven markets such as MISO, we expect installed gas generation capacity and the amount of power generated from gas to rise, as low-cost gas replaces coal. In 2020, gas is approximately 23 percent of MISO’s generation mix and will grow to nearly 70 percent by 2040.
In policy-driven markets, however, we expect the amount of power derived from gas plants to decline steeply and capacity to remain high. Indeed, gas will likely act as a bridge fuel in policy-driven markets, with value increasingly attached to its capacity (rather than its generation) in order to provide long-duration flexibility solutions. This pattern becomes apparent in daily gas generation: the average firing of plants declines over time, though spikes in gas generation occur around peak power-consumption times (Exhibit 6). The value of these plants is no longer in the form of gas molecules, representing the amount of electricity they generate, but in the form of steel—the plants exist chiefly to provide power when other sources, such as wind and solar, cannot.
Grid flexibility becomes a much more acute need in policy-driven markets
In grids with substantial levels of renewable generation, flexible solutions will be needed to smooth out imbalances between demand for power and the intermittent supply from renewable sources. These solutions include batteries (which today can cover intermittency gaps for a period of two to five hours), technologies to actively manage demand, and longer-duration options such as pumped hydro storage and dispatchable gas plants. The extent, timing, and mix of solutions will vary, depending on the characteristics of the policy-driven market. For example, in large, diversified markets with substantial solar resources, like California, shorter-duration battery storage could play the biggest role; we expect 48 gigawatts of battery capacity in the state by 2050. While wind-heavy markets like New York still need short-term battery storage, covering potential multi-day periods without wind requires longer-duration storage and more transmission interconnections.
Decarbonization will challenge power market structures
Power market structures have traditionally worked well under three conditions: when power plants can be deployed on demand, when their levels of utilization are relatively stable, and when marginal costs make up a large share of the overall cost of operations. As regions move toward solar, wind, and flexibility solutions, the ways in which generation and flexibility assets operate change. Consequently, power market structures will also need to change.
In policy-driven markets, gas plants that now have predictable running patterns will operate less often and more intermittently. Many markets will have increasing amounts of battery storage (Exhibit 7), which runs intermittently by its nature. And, of course, renewable plants themselves operate only when the sun shines and the wind blows.
These dynamics mean that operators will need to rethink their market designs, including how they provide incentives for and compensate the best outcomes for the grid and customers. For example, NYISO has iterated on a buyer-side mitigation measure that sets floor prices on batteries. It is also working on proposals to revise its capacity markets to account for decreasing average utilization of assets. ISO–NE is testing innovative ways to encourage downstream assets such as demand-response programs and home-located batteries. These assets contribute to grid flexibility by creating mechanisms for demand-response assets to act as generators in energy and reserve markets.
Market operators will also need to determine whether and how they account for the cost of carbon emissions, particularly those that are emitted outside the market’s borders. For instance, the NYISO region borders PJM and is connected by roughly four gigawatts of transmission capacity. As New York implements its decarbonization targets, its market structures will need to decide how to offset the relatively higher carbon intensity of the power it imports from PJM.
Our analysis illustrates the extent of the policy-driven differences in the power sector that have emerged across the country. The implications for companies operating in the sector are enormous. Owners of gas power plants, for example, could see rising demand for their output and favorable conditions for new plants in cost-driven markets but rapidly decreasing utilization, high operational volatility, and tougher prospects for new investment in policy-driven markets. Electric utilities could see a range of outcomes—from limited disruption in the cost-driven markets to a rapid increase in electrification and growth of centralized and distributed renewables in policy-driven markets, along with a host of modernizing and capacity-increasing investments in the electric grid to accommodate those changes.
