Decarbonization of the Power Sector with CCS: Case Study in Two Regions in the U.S., MISO North and SPP RTO West

Abstract

This paper estimates potential changes in the total system cost (TSC) of decarbonization of two regional transmission organizations (RTOs) in the United States (U.S.)—Midcontinent Independent System Operator-North (MISO-N) and Southwest Power Pool (SPP) RTO West. In particular, the study serves to highlight potential differences in technology costs between two decarbonization pathways at carbon reduction rates close to 100% (relative to 2019 levels) while maintaining system reliability. In Pathway A, decarbonization is achieved by replacing fossil energy (FE)-fired thermal power plants with variable renewable energy (VRE) technologies coupled with energy storage (ES). Pathway B considers retrofitting fossil fuel-fired units with carbon capture and storage (CCS) and the addition of VRE and ES. The results show that including CCS technologies in the path to decarbonization has a significant benefit from a system cost perspective. When summing up all system costs and avoided emissions over 30 years of operation of the decarbonized systems, the pathway that includes CCS is significantly more cost-effective. TSCs for MISO-N are at least USD 1279 billion (B) and at most USD 910 B under Pathways A and B, respectively. For SPP RTO West, Pathway A TSCs are at least USD 230 B, and Pathway B TSCs are at most USD 153 B. TSCs of Pathway A are 1.4–8 times larger than the total system costs of Pathway B. When CCS is not included, the cost per ton of carbon dioxide (CO₂) avoided is estimated to be USD 124–489/ton for MISO-N and USD 248–552/ton for SPP RTO West. When CCS is included, the cost of avoided CO₂ is projected to decrease by 29–87% (mid-point estimate of 73%) with values varying between USD 64 and 114/ton and USD 74 and 164/ton for MISO-N and SPP RTO West, respectively. These differences highlight the need for consideration of all low-carbon-intensive technology options in cost-optimal approaches to deep decarbonization and the value of CCS technologies in the energy transition.

1. Introduction

The global power sector is undergoing fundamental changes led by policy action, technology innovation, and climate mitigation efforts [1]. Electricity systems worldwide are evolving their mix of generation technologies in response to changing fuel prices, changing technology capital costs, environmental goals, and the focus on curtailing carbon dioxide (CO₂) emissions. Power generation entities are choosing to decarbonize their power systems for the most part by adopting variable renewable energy (VRE) and energy storage (ES) and retiring fossil energy (FE)-based generators—that is, “replacing” CO₂ emissions-intensive power generators with low-carbon generators [2]; however, geopolitical changes, resource shortages, and extreme weather events have led to questions regarding the feasibility of this pathway within the decarbonization time horizons.

1.1. The Value of CCS in Deep Decarbonization Pathways

The inclusion and potential prioritization in the energy transition of the deployment of carbon capture and storage (CCS) technologies is necessary. CCS technologies support decarbonization efforts while maintaining the use of dispatchable FE power plants simultaneously with large-scale integration of VRE and ES [3,4,5,6]. CCS deployment has been recognized in many studies [2,3,7,8,9,10,11,12,13,14,15] as an important element in achieving decarbonization as part of a larger discussion of a clean energy strategy that considers all energy uses in addition to the power sector, globally and in the United States. The Sixth Assessment Report (AR6) of the Intergovernmental Panel on Climate Change (IPCC) released in 2021 notes that CCS is key to mitigating climate change and reaching net-zero emissions by mid-century, with six of the seven Illustrative Mitigation Pathways (IMPs) for decarbonization, including carbon capture and carbon removal technologies, having a significant role [7]. British Petroleum’s (BP) Energy Outlook 2023 [8] shows that carbon capture utilization and storage (CCUS) will remove approximately 4 gigatons of carbon emissions globally in the Accelerated scenario and 6 gigatons in the Net Zero scenario by 2050 of a projected total CO₂ emission of approximately 30 gigatons by 2050. Moreover, in BP’s 2020 energy outlook edition, the projections for the Rapid and Net Zero scenarios suggest that the average annual investment of CCUS between 2020 and 2050 of approximately USD 80–150 billion (B) is significantly less than that required for upstream oil and gas production and for wind and solar [9] (USD 300–450 B for upstream oil and gas production and USD 500–700 B for wind and solar [9]). In the Sustainable Development scenario (i.e., Net Zero) from the International Energy Agency (IEA) Energy Technology Perspectives (ETP) 2020 report [10], the IEA projects CCUS to account for 15% of the total cumulative carbon emissions savings globally in 2070 compared with the Stated Policies Scenario, with its role and contribution growing over time.

This paper contributes to the body of research that evaluates the “deep decarbonization” of the U.S. power sector, defined by Jenkins et al. [11] as an 80–100% reduction in CO₂ emissions from current levels. It contributes specifically to presenting a deep sub-national decarbonization analysis. While numerous studies have assessed the costs of deep decarbonization [2,3,8,10,14,16,17,18,19,20] and the literature agrees that costs increase drastically after 50–80% rates, there is still a need to understand specific advantages of introducing CCS for over 80% decarbonization rates at the sub-national level. Most of today’s literature covering deep decarbonization is not focused on understanding the implications of wide-scale deployment of CCS in the power sector at the sub-national level, and the literature that considers CCS has diverging conclusions in terms of its need as a clean firm resource. For instance, about half (44%—out of 43 reviewed studies on deep decarbonization, 19 include CCS in their least-CO₂ solution. These studies are listed in Appendix B, see in the table the last column, which lists the 19 studies that include CCS in their solution) (19) [3,13,14,15,18,19,20,21,22,23,24,25,26,27,28,29,30,31,32] of the 43 studies that evaluated deep decarbonization considered or resulted in the selection of CCS for the lowest CO₂ cases [11]. The other half (22) did not include CCS as a technology that leads to the least CO₂ solution. From the half that included CCS, four [3,14,22,27] covered a sub-national study—in the Western Interconnect, Texas, California, Wisconsin, and New England in the United States, and in Sichuan, China. From the other half that did not include CCS, only three were conducted at the sub-national level—in the Western Electricity Coordination Council (WECC) region, an ERCOT-like system, and California—but none of these included CCS as part of their least-CO₂ solution [33,34,35].

1.2. Contributions to the Literature

Therefore, there is still a gap in addressing deep decarbonization studies and evaluating the value of CCS for most sub-national regions in the United States. There are no deep decarbonization studies at the sub-national level that have been published in the literature covering the U.S Midwest or Southwest Power Pool (SPP) regional transmission organization (RTO) West, regions of focus of this analysis. Although interesting and relevant, many of the considerations of studies across the globe, nationally and sub-nationally, do not reflect the characteristics of the Midcontinent Independent System Operator (MISO) and SPP electricity markets, particularly when considering system reliability. The first contribution of this paper is to address this gap by investigating the decarbonization of specific U.S. regional sub-national markets. In particular, MISO and SPP RTO West were considered due to their current heavy reliance on fossil-fired generation fleets and are representative of the diversified U.S. electricity markets where decarbonization could entail a significant system cost. Moreover, the U.S Midwest is a highly industrialized region and has a large economy comparable to the size of a country. These two regions are quite different in the amount of capacity installed but relatively similar in the share of FE dependency, with over 55% of the total system capacity being FE-fired units. The MISO system is large enough to showcase conclusions for industrialized regions and even countries [36]. (An initial version of this work was presented at the International Association for Energy Economics/Latin American Energy Economics Meeting conference, and MISO-North was compared to Argentine and Chilean systems due to their FE-dependence, seasonality, and low hydro base [36]). In 2021, MISO released an in-depth study on fleet transition within its footprint through 2040 as part of its regional “Reliability Imperative”. The MISO Futures study [12] includes natural gas combined cycle generation with CCS (referred to as CC+CCS) as a technology option for achieving 81% decarbonization relative to 2005 levels. Apart from the Futures study, there is little research available in the literature examining deep decarbonization of MISO or the SPP region, and, to the extent of the authors’ knowledge, there is no analysis that is above 80% decarbonization in these regions.

The literature is divided in its stance on the need for CCS, and within the studies where CCS is touted to be indispensable to achieve deep decarbonization, there is still a need to model and analyze system costs. There are somewhat differing statements on the role of CCS in achieving deep decarbonization in a cost-effective way. For example, a sub-national analysis in China [14] concludes that the CCS pathway, while being indispensable in enabling 100% decarbonization from a maximum of 52–90%, is the most expensive. On the other hand, a New England and Texas study [3] shows that CCS is a firm low-carbon technology that decreases the average cost of electricity dramatically compared to the case with only fast-burst and fuel-saving technologies. Inspired by the diverging results in the literature on the role of CCS in unlocking deep decarbonization and the implications on system costs, this paper aims to investigate system-level costs between two pathways, one without CCS and the other with CCS, to contrast them directly. The second contribution of this paper is to investigate two bounding pathways for achieving decarbonization rates close to 100%, aiming to address the CCS conundrum. Pathway A is the case in which deep decarbonization is achieved without CCS, and Pathway B is the case in which CCS is also included. The results highlight the maximum difference in the inclusion of CCS in the ongoing energy transition, which represents the maximum potential savings that CCS can achieve. In Pathway A, decarbonization is achieved by replacing fossil fuel-fired thermal power plants with VRE technologies coupled with ES. Pathway B considers retrofitting all existing fossil fuel-fired units with CCS as a means of decarbonization in addition to VRE and ES. This comparative analysis is built with a business-as-usual (BAU) baseline and introduces one single major change in order to isolate the impact of the inclusion of CCS. The cost per avoided ton of CO₂ is estimated for both pathways, enabling evaluation of the trade-offs between VRE and VRE+CCS technologies from a system-level perspective. While numerous studies evaluate portfolios that introduce more decarbonization technologies (e.g., hydrogen) and various capacity deployment mixes, this paper’s technology-limited portfolio is defined with the purpose of elucidating the impact of CCS on the cost-effectiveness of the system.

The third contribution of this paper is the inclusion of robust cost and performance estimates of the CCS technology, disaggregated as both greenfield CCS, and retrofit CCS, on a per-plant basis. In the literature, there is a limited discussion of the role of retrofits and greenfield CCS technologies to facilitate the energy transition and VRE technologies; less prominent is work that analyzes plant by plant in a sub-national region and considers the efficiency and parasitic loads associated with retrofitting existing operational units with their unique technical attributes, such as heat rate and age. This analysis starts with the plant-level, using a bottom-up approach to build the total system cost estimates for Pathway B. Although CCS is a mature technology that has been documented and researched extensively, and there is an analysis of decarbonization pathways with CCS, a comprehensive analysis that identifies on a per-plant basis the costs of retrofitting existing fossil units and adding new fossil power plants with CCS provides more robustness to existing system cost estimates.

The fourth contribution of this paper refers to the type of analysis performed with high-resolution data. The comparative capacity expansion analysis with hourly level data is data-intense at a higher resolution than traditional capacity expansion studies. The higher resolution allows for capturing hourly operational dynamics and presenting total system cost estimates that incorporate seasonal, monthly, daily, and hourly variability. Pure capacity expansion studies usually are not carried out at hourly time resolutions. They are set to minimize the cost of the portfolio of technologies, choosing the capacity mix that minimizes a cost function [13,14,15,16] based on time slice approaches that capture representative, weather-normalized days or seasons. Some wider-economy models embed capacity expansion modules to represent the decarbonization of the power sector in tandem with other economic sectors [8,17,18], which also sacrifice temporal resolution in lieu of larger geographic or sectoral footprints. The capacity expansion is modeled using the National Energy Technology Laboratory (NETL) System Cost of Replacement Energy (SCoRE) tool developed based on the prior work of Byrom et al. [11] and applied in [2]. Thus, the technology choices defined ex ante (e.g., retrofit all existing fossil power plants with CCS) will dictate the magnitude of the expansion required and the resulting power capacity that satisfies system resource adequacy requirements and obligations. In both pathways, decarbonization is achieved without sacrificing time resolution, that is, the ability of the system to meet projected hourly loads over the entire year, which uniquely sets the current study apart from conventional expansion analysis.

The fifth and final contribution of this paper is the systems approach to estimating costs under each pathway. This means that costs are estimated including capital and operational costs, as well as costs of deploying additional sustaining infrastructure [11]. It also means that costs are assessed in the long term. Most states in MISO and SPP RTO West, despite being in market regions, still require utilities to submit Integrated Resource Plans for Public Service Commission/PUC approval, but those typically only look forward across a 10-year time horizon for resource additions/retrofits. In addition, the market timelines are even shorter than the Integrated Resource Plans (IRPs), creating a combination of myopic forces that could potentially disincentivize capital-intensive projects such as CCS that have high upfront costs and are more cost-effective over time. Results are presented as total system costs over a 30-year period, assuming the operation of the decarbonized system for 30 years. Annual costs are highlighted, as these are significant [12], and they are passed on to electricity consumers through retail rates. This system approach enables a comparison of the resulting total system costs across different technology choices. It is worth noting that some studies have compared the costs and performance of numerous low-carbon technologies based on the levelized cost of energy (LCOE) [19,20,21,22] and not on total system cost (TSC), which implies that although multiple technologies are compared based on their overnight costs and baseline performance, they are not compared based on their contribution to a specific system nor on their complementarity to other resources. The LCOE, while useful for considering the costs of multiple technologies, fails to account for relevant aspects to adequately evaluate the adoption of such technologies in the context of a specific system (for example, LCOE does not take into consideration the time pattern and duration of energy production, which ultimately determine the value of output to meet demand in a specific system. LCOE does not capture wider system costs and long-term implications of implementing certain technologies as the generation mix diversifies; it likely overvalues intermittent, energy-constrained generating technologies over those that are dispatchable and does not consider aspects such as high storage deployments, upgrades, and/or backup energy needs or flexibility to maintain system stability, which are all factors that could increase the total system costs) [11,23,24,25,26].

1.3. Beyond Costs—Value of Adding CCS in a VRE Decarbonization Pathway

Also, technology choices matter for reasons beyond costs. Although not explicitly included in this analysis, a more diversified portfolio of technologies can arguably be more desirable than a less diversified portfolio, all things being equal [37], particularly at high decarbonization levels and under extreme weather conditions [38]. Supply chain bottlenecks for the manufacture of ES and VRE are one example of the importance of considering other technologies that will enable decarbonization of the power sector at the pace needed to meet public policy goals. Also, CCS technologies can extend the life of existing fossil-based infrastructure and its supporting supply chain and maintain energy communities while reducing at least 90% of its carbon emissions footprint [39]. While these aspects are critical, this analysis does not consider externalities or other benefits to the electric system or economy, including resource adequacy gains of maintaining CCS-based FE-power generation as critical resources in a diversified power supply mix, or supply chain implications associated with the technology choices modeled.

This paper is organized as follows: Section 2, Methods, covers methods used to evaluate the capacity expansion of the systems under a decarbonization constraint; Section 3, Data, includes a data summary of the costs, demand, and supply of each of the regions analyzed; results are presented in Section 4; and finally, the paper concludes in Section 5 with the main conclusions.

2. Methods

This study relies on the System Cost of Replacement Energy (SCoRE) metric developed by [40] and the “SCoRE tool” developed by [2] to account for the TSC implications of replacing high carbon-emitting technologies with low carbon-emitting technologies from both cost-effectiveness and reliability perspectives. The SCoRE tool matches the hourly load with the available technologies, constrained by technology ramping rates, minimum operating levels, and other technical characteristics of the available electricity mix. The SCoRE tool is used as a simplified capacity expansion model, running with hourly data to evaluate sub-national regions in the United States represented as a uni-nodal system (i.e., no transmission constraints). Technologies are chosen through a “what if” analysis approach. Thus, the SCoRE tool does not minimize total system costs for a future year but instead estimates system costs when one technology is chosen as the main capacity expansion driver to achieve a decarbonization target without any loss of load in every hour of the year. This approach allows for testing differences at the extremes (i.e., when a large amount of VRE is deployed versus a large amount of CCS), which is useful for drawing comparisons.

For the base year (BAU case, 2019), the system economic dispatch data are known, satisfying the load generation balance. For the future year, the system’s hourly economic dispatch is determined by adjusting the hourly generation of each technology to meet future hourly load and replacing retirements or derated power output of retrofitted units. The system in future years meets the following conditions:

$$\sum _{tech=1}^T\left({CapBAU}_{tech}-{CapRET}_{tech}+{CapADD}_{tech}\right)\times {CFBAU}_{tech,h}-\sum _{CCStech=1}^{CCST}{CapDer}_{CCStech}\times {CFBAU}_{CCStech,h}={L\_FUT}_h+\forall h=\left\{1,2,\dots ,8760\right\}$$

(1)

And constraints:

$${AE}_{FUT}=DecarbRate\times {AE}_{BAU}$$

$$GenerationLimits:P_i^{MIN}{\le P}_i\left(t\right)\le P_i^{MAX}$$

$$RamprateLimits:P_i\left(t\right)\le P_i^{MAX}$$

In Equation (1), ${CapBAU}_{tech}$ is BAU or existing capacity of technology tech; ${CapRET}_{tech}$ is the retired capacity of technology tech; ${CapADD}_{tech}$ is the capacity additions of technology tech; ${CFBAU}_{tech,h}$ is the known capacity factor for hour h of technology tech in the BAU; ${CapDer}_{CCStech}$ is the derated capacity or capacity loss due to CCS retrofits; ${CapBAU}_{CCStech}$ is BAU or existing capacity of CCS technology; ${L\_FUT}_h$ is the load in year 2035 in hour h; ${AE}_{FUT}$ is the total annual emissions of the decarbonized system by future year; $DecarbRate$ is the percentage of emissions that are still emitted; and ${AE}_{BAU}$ are annual emissions in the BAU case. The BAU is the known system of 2019, the future year chosen is 2035, and the decarbonization rate is 98.8%.

This analysis includes two major pathways, both reaching a 98.8% reduction in annual emissions compared to the BAU (2019): a VRE-centered pathway and a CCS-centered pathway. Each pathway is represented by two cases: Pathway A is represented by cases 1 and 2, and Pathway B is represented by Cases 3 and 4. These four separate cases are considered for each region. The two pathways and their cases are described as follows:

• BAU case: The system operates for 30 years as in 2019, with no changes to demand or supply of power and no decarbonization goal to meet.
• Pathway A, the “VRE-Centered” pathway: The system reaches a 98.8% decarbonization level compared to the BAU. Annual demand is the forecasted demand of 2035 applied to 30 years of operation. Hourly load is met via the minimum fossil fuel capacity possible. All steam turbine (ST) coal, natural gas combined cycle (NGCC) and ST natural gas (NG), and most combustion turbine (CT) and internal combustion (IC) units, retire. These technologies are replaced by the addition of new wind, solar photovoltaic (PV), and energy storage. Other renewable technologies, such as biomass, are not included due to limited potential in the region (biomass is not considered in the two regions due to the lack of forest residues and a biomass industry. This is unlikely to change due to the importance of a significant area that is currently and will continue to be critical for agricultural production, both crops and livestock. There are very few biomass power plants in the MISO North and SPP regions [41]. While these regions have significant agricultural residues, they lack the density of woody biomass to sustain a large-scale woody biomass plant for a 30-year lifetime. Agricultural residues have been suggested, but their need to reduce soil erosion and provide nutrients for soils makes them unlikely candidates for energy production [42]. Additionally, many agricultural residues contain high amounts of ash-containing elements that may cause numerous technological and environmental problems during biomass combustion, including pitting of combustion chambers [43], which limits the feasibility of deployment of these projects in the future) [41,42,43]. In Equation (1), ${CapADD}_{tech}$ is adjusted for solar, wind, and ES technologies, and ${CapRET}_{tech}$ is adjusted for NGCC, ST Gas Units, ST Coal Units, and CT/IC /Oil Units. VRE capacity additions need to fully replace the dispatched generation of retiring fossil fuel plants and meet future year load. Also, ${CapDer}_{tech}=0$ because there are no FE units that are retrofitted with CCS. This pathway is represented through two slightly different cases: Case 1 and Case 2.
• Case 1—VRE: The system expands through capacity additions of only wind and solar PV. (The VRE expansion can be achieved through an infinite combination of solar PV and wind installations. In the present study, the ratio of the solar-to-wind capacity installation was maintained at ca. 2019 levels, ~0.07 for MISO-N and ~0.20 for SPP RTO West as a first approximation. The TSC has been found to generally increase as this ratio increases [2] due to the lower LCOE coupled with the larger effective capacity factor for wind installations relative to solar plants.)
• Case 2—VRE+ES: The system expands through capacity additions of wind, solar PV, and ES.
• Pathway B, the “CCS-Centered” pathway: The system reaches a 98.8% decarbonization level compared to the BAU. Annual demand is the forecasted demand of 2035 applied to 30 years of operation. Hourly load (2035) is met via the retrofit of existing NG capacity with CCS (at 97% capture) or coal-fired capacity with CCS (at 99% capture), the addition of greenfield NGCC units with CCS technologies (97% capture), and the addition of new VRE capacity. A significant share of CT/IC units retire. This case allows for the addition of new VRE. In Equation (1), ${CapADD}_{tech}$ is adjusted for solar, wind, NGCC, and STNG with CCS (retrofits and greenfield), and ST Coal with CCS (retrofits). VRE+FE with CCS additions need to fully meet future year load, accounting for CCS power and heat requirements of the retrofitted units. This pathway is represented by two slightly different cases: Case 3 and Case 4.
• Case 3—NGCC+CCS: All coal-fired plants retire, but existing gas plants (NGCC and ST Gas) are retrofitted with CCS. The retirements are compensated for with the addition of greenfield NGCC with CCS and VRE.
• Case 4—NGCC and Coal+CCS: Coal does not retire. Both coal and NG plants are retrofitted with CCS but only Greenfield NGCC with CCS is considered.

TSCs are estimated for each region for each case as the net present value (NPV) of the total overnight costs incurred over 30 years. Following the approach of Byrom et al. [40], where total system costs are differentiated by technology type, the total technology costs are defined as the sum across all costs incurred by new and existing power plants of that technology:

$${TSC}_{Region,Case}=NPV\left(\sum _{tech=1}^T{TOC}_{tech}+{{OM}_{tech}+T\&D}_{tech}+{OTHER}_{tech}\right)$$

(2)

In Equation (2), ${TSC}_{Region,Case}$ and all the components on the right side of the equation are in any suitable currency unit. In this analysis, all values are maintained in million USD.

${TSC}_{Region,Case}$ is the TSC aggregated across T technologies and that maintains the system in operation for 30 years; Region represents an electricity market (or portion of it); and Case represents Cases 1–4.

${TOC}_{tech}$ represents the total overnight costs associated with investment expenditures for new capacity including decommissioning and dismantling expenditures for retiring capacity. ${TOC}_{tech}$ is estimated by multiplying costs per MW by total additional or retiring capacity (MW) and is assumed to be incurred overnight.

${OM}_{tech}$ represents total operation and maintenance (O&M) costs, which is a sum of non-fuel variable O&M (VOM) costs, fuel costs (FUEL), and fixed O&M (FOM) costs, and is estimated by multiplying the cost per MW or per MWh by the total installed capacity (MW) or generated power (MWh), respectively, over 30 years.

${T\&D}_{tech}$ represents the transmission and distribution costs associated with the interconnection of additional power capacity and is estimated by multiplying costs per MW by additional capacity (MW).

${OTHER}_{tech}$ represents other costs; for wind and solar PV, these costs are additional balancing costs, in addition to construction of new transmission capacity, and are reported by the literature as costs associated with new flexible capacity or additional balancing reserve requirements, estimated as the multiplication of costs per MWh and total generation (MWh). For FE-fired power plants, these costs include the transportation and storage cost of CO₂ (USD/ton) translated in a per-MWh value and multiplied by total generation (MWh).

Total system cost analysis is conducted assuming the following: costs of new capacity and decommissioning and retirement of existing capacity happen overnight; the fully decarbonized system operates for 30 years; and an annual discount rate of 5% is representative for 30 years. Additionally, dollar values are in 2018 USD value unless otherwise specified.

3. Data

3.1. Generation and Load Data

The analysis was conducted using day-ahead (DA) hourly generation by fuel and technology type and hourly load in 2019, in MWh, in two sub-regions: MISO-North (MISO-N) and SPP RTO West [44]. MISO-N is a large territory linked to the MISO-South region by a main transmission link. MISO-N was chosen as a study area due to its being a large, fossil generation-heavy region with high seasonality. The existing fleet capacity, demand, and regional location made MISO-N an ideal region to study the effects of the transition to a highly decarbonized fleet. SPP RTO West was chosen as a study region due to it being a smaller, recently formed region in the Western Interconnection with a fossil generation-heavy fleet makeup. The size difference between MISO-N and SPP RTO West enabled the identification of the effects of the transition to a highly decarbonized fleet. Details for each data set are presented in

Table 1. Data sources.

Data	Source of Data	Notes
Hourly Load Data For The Bau (2019)	Hitachi Energy PROMOD [44]	Data are sourced from FERC [45] and EIA [46] as well as other ISO publications.
Hourly Load Data For Future Year (2035)	Hitachi Energy PROMOD [44]	Hourly load for each transmission system is forecast to 2035 using monthly peak and energy values, applied to a representative 8760 hourly load based on historical hourly loads for each transmission zone. Monthly peak and energy forecasts through 2035 are based on FERC 714 data [47] for both regions.
Hourly Generation Data For The Bau (2019)	Hitachi Energy PROMOD [48]	A Hitachi Energy PROMOD dispatch analysis was run for each sub-region. MISO-N and SPP RTO West (it was possible to directly obtain historical 2019 data of the full ISO or region (all U.S. footprint of MISO or SPP); however, to obtain historical data of the sub-region, a dispatch run had to be performed) wind and solar VRE hourly generation are based on 8760 hourly generation profiles sourced from NREL data, varying by location. Net imports are calculated from hourly transmission flows between models.

FERC = Fossil Energy Regulatory Commission; EIA = Energy Information Administration; NREL = National Renewable Energy Laboratory.

.

3.2. MISO-N and SPP RTO West System Models

MISO-N is a sub-system within MISO’s footprint in the United States. It consists of the East, Central, and West regions of MISO, and excludes the MISO South region, as presented in Figure 1. MISO-N comprises approximately two-thirds of the full U.S.-MISO footprint in terms of installed capacity, with a total of 129,559 MW of installed capacity and 92 GW of peak load.

The MISO-N BAU system (2019) is shown in Figure 2 [49]. Approximately 69% of the installed capacity in this system comprises FE-fired units. The MISO-N system in 2019 was constructed using the Hitachi Energy PROMOD economic dispatch model with the 2021 Eastern Interconnection simulation-ready data set. Net annual imports represent approximately 8% of the total load in 2019. More details of the BAU system can be found in

Table A2. Details of SPP RTO West Power System in 2019 (BAU).

Tech/Fuel	Category	MW	MWh	Average CF
NGCC and ST Gas	Fossil based	3870	7,345,727	21.67%
Hydro	Traditional RE	3671	11,888,479	36.97%
CT/IC Gas/Oil	Fossil based	3788	205,960	0.62%
Other	Biomass and Other	17	51,297	33.47%
Biofuel/Biomass	Biomass and Other	39	225,851	66.28%
Coal	Fossil based	6141	30,205,416	56.15%
Interruptible Loads	Biomass and Other	232	0	0.00%
Pump Hydro Storage	Traditional RE	563	854,641	17.34%
Wind	VRE solar + wind	4540	13,498,787	33.94%
Solar	VRE solar + wind	1091	2,142,506	22.42%
Geothermal	Traditional RE	18	58,612	36.76%
Total Gen	Supply Resources	23,970	66,477,277	31.66%
Net Imports	Supply Resources		0
Total Load	Demand		66,477,277

of Appendix A.

Figure 3 shows the hourly DA load for 2019 and the projected 2035 hourly load [44], and Figure 4 shows the total energy demand (MWh) and annual peak load (MW). FE generation met 68% of the total electricity demand in 2019. By 2035, system non-coincident peak load and total energy demand grow almost 10%, from 92 GW in 2019 to 101 GW in 2035, and from 504 TWh to 553 TWh, respectively. Most of the region’s power demand is met with internal resources, with net annual imports representing approximately 8% of the total load in 2019.

SPP RTO West is a sub-system within SPP and is shown in Figure 5. Approximately 57% of the installed capacity in this system comprises FE-fired units.

The SPP RTO West system model is built from the 2020 Western Interconnection simulation data set provided by Hitachi Energy. (The SPP RTO West region did not exist in the model and needed to be created. To assemble the SPP RTO West region in the model, a new model region was created, and the following transmission zones were moved into that region based on information available from SPP [51]: Idaho Power; Public Service of Colorado—East; Public Service of Colorado—West; Western Area Power Administration (WAPA)—Colorado Missouri (Colorado East); WAPA—Colorado Missouri (Colorado West); WAPA—Colorado Missouri (Wyoming); and WAPA—Upper Great Plains West. Transmission links between zones, both within and external to the new region, remained unchanged.) Net imports for the BAU (2019) were less than 1 MWh. SPP RTO West BAU is shown in Figure 6 [44]. More details of the BAU system can be found in Table A2 of Appendix A.

Figure 7 shows the hourly DA load in SPP RTO West for 2019 and the projected 2035 hourly load, both from [44]. Figure 8 shows demand growth in the region from 2019 to 2035. Peak load in the region grows from 14 GW in 2019 to 15 GW in 2035, and total demand grows from 66 TWh to 75 TWh.

While the baseline year is 2019, it is still valid for today’s most recent available data for MISO and SPP (year 2022), given the reduction in energy demand seen during the COVID pandemic. For example, 2022 demand in Load Regional Zones 1–7 of MISO (which constitute MISO-N in this analysis) was approximately 491,000 GWh, approximately 2.8% lower than its annual demand in 2019, presented in this study.

3.3. Cost Data

The following cost variables were compiled for existing and greenfield (i.e., new and retrofitted) power capacity: total overnight cost (TOC) (USD/kW) of greenfield capacity; decommissioning and dismantling (D&D) costs of retiring power plants (USD/kW); annual FOM costs (USD/kW) of existing and greenfield capacity; annual non-fuel VOM costs (USD/MWh) of existing and greenfield capacity; FUEL costs (USD/MWh) of existing and greenfield capacity; transmission and distribution (T&D) costs of greenfield capacity (T&D costs, when available in USD/MW in PacifiCorp IRP, were translated into USD/MWh assuming capacity factors of 35%, 40%, and 70%, for solar PV, wind, and natural gas, respectively, and a lifetime of 20, 30, and 40 years, respectively); other integration costs (OTHER), including costs associated with balancing of variable generation (USD/MWh); and CO₂ transport and storage (T&S) costs (USD/MWh) of greenfield capacity.

Data come from various sources: TOC, FOM, VOM, FUEL, and T&S come from NETL Fossil Energy Baseline report Rev 4A (the NETL baseline report compares various FE-fired power plants with CCS configurations. This analysis assumes the retrofits’ costs and performance are similar to the coal steam turbine supercritical case, with a 99% capture rate (case B12B.99 in the report), and the NGCC with a 97% capture rate (case B31B.97 in the report)) for greenfield CCS [39] and CO₂ Capture Retrofit Database (CCRD) for CCS retrofits [52], NREL baseline national resource class 1–10 database [53], EIA Annual Energy Outlook Table 55 and 8.2 [46], PNNL energy storage database [54], and S&P Global [55]. T&D costs come from PacifiCorp IRP [56] and Gorman et al. [57]; balancing variable generation costs come from Milligan et al. [58], Hirth et al. [59], and Luckow et al. [60]; and D&D costs come from Burns and McDonnell [61]. The upper and lower bounds, as well as the mid-point values, were constructed using all sources available. (Most of the estimates used are not constrained to one single source of information but multiple sources that were combined and analyzed in detail per technology.) All the data used are for the U.S., except operational and maintenance data (from S&P Global), which are specific to MISO and SPP. The T&D costs used are gathered from one single source (PacifiCorp) in the U.S.

Figure 9 shows that TOCs of the six greenfield and retrofitted technologies categories (Retrofitted Coal with CCS, Retrofitted NGCC with CCS, Greenfield NGCC with CCS, Solar PV, Wind, and Energy Storage of 10 h duration) range from USD 1000 to 5000/kW, with the largest variation seen in energy storage technologies. TOCs of retrofitting coal units with CCS at 99% capture are similar to deploying greenfield NGCC with CCS at a 97% capture rate—in the range of USD 2500–2800/kW. Retrofitting NGCC units with CCS at a 97% capture rate is the cheapest retrofitting option, with a TOC of USD 1600–1900/kW. D&D costs of retiring units vary across the three technology categories considered (CT or IC Gas/Oil, NGCC and ST Gas, Coal), with costs as low as USD 1/kW and as high as USD 500/kW. Figure 10 details ES costs. It shows the TOC of the six ES technologies considered, ranging approximately between 1000 and 4800/kW.

Figure 11 shows that, in terms of annual costs, FOM and fuel costs are the most significant for the retrofitted or greenfield CCS fossil technologies, and FOM costs are the most significant for wind, solar, and ES technologies. The T&S cost of CO₂ (OTHER) of the coal retrofitted units is similar to VOM costs, at approximately USD 10/MWh. The T&S cost of CO₂ (OTHER) of the NGCC retrofitted units is, as expected, much lower than the coal case (approximately USD 4/MWh) but also comparable to the VOM of these units, approximately USD 5/MWh. While solar, wind, and ES technologies do not have fuel costs, solar and wind have T&D costs of USD 3–10/MWh associated with the deployment of new transmission and distribution lines that accommodate these resources and OTHER costs associated with other integration costs not captured in T&D, approximately USD 5/MWh.

As shown in Figure 12, the fuel costs of fossil units without CCS range from USD 7 to 15/MWh for NG units and USD 7 to 145/MWh for coal units, with an average of USD 123/MWh for both fuels/technologies. These were maintained over the life of the study for the fossil energy units that remain in operation and that are not retrofitted with CCS. Fuel costs of greenfield and retrofitted NGCC with CCS units at 97% capture rate are USD 31/MWh and USD 42/MWh, respectively. Fuel costs of the retrofitted supercritical coal steam turbine with CCS units at a 99% capture rate are USD 26/MWh.

3.4. CCS Retrofits of MISO-N and SPP RTO West

Table 2. Coal ST and NGCC units in MISO-N and SPP RTO West available to retrofit with CCS.

Region and Fuel	No. of Units *	Capacity per Unit (Min, Average, Max) *	Total Capacity * (Nameplate) (Summer)	Average CF **	Fuel Costs *** (USD/MWh)	Average Annual CO2 Emissions Rate (lbs/MMBtu)
MISO-N coal	114	25 MW, 436 MW, 939 MW	49,653 MW 45,396 MW	53%	20	189
MISO-N NG	39	33 MW, 438 MW, 2049 MW	17,080 MW 15,176 MW	56%	28	94
SPP RTO West coal	18	75 MW, 311 MW, 857 MW	5590 MW 5078 MW	72%	16	203
SPP RTO West NG	15	74 MW, 289 MW, 868 MW	4335 MW 3629 MW	42%	42	111

* Available to retrofit in the NETL CCRD; ** Coal units over 2018–2020 and NG units over 2019–2021; *** 12-month weighted average (2019). Costs in 2018 USD.

shows the number of coal-fired steam turbines and combined cycle natural gas plants in each region that were considered for a CCS retrofit based on 2019 data. While MISO-N is a much larger system, both MISO-N and SPP RTO West have a significant number of units available to retrofit with CCS. There are a total of 49.7 GW and 5.6 GW of coal units in MISO-N and SPP RTO West, respectively, which are available to be retrofitted according to the NETL CCRD Database. The NG units sum up approximately 17.1 GW in MISO-N and 4.3 GW in SPP RTO West. Their average annual emissions rate range is approximately 100 lbs/MMBTU and 200 lbs/MMBTU for the NG and coal units, respectively. The fuel costs of these units are USD 16–42/MWh depending on the region and fuel/technology. The fuel cost data, aggregated, are also presented in Figure 11.

3.5. CO₂ T&S Costs

The transport costs presented are based on established benchmarks and models that account for average conditions and typical scenarios, ensuring a representative estimate for the regions in question. A Midwest average of USD 10/ton was used as the cost associated with T&S of captured CO₂ via CCS in MISO-N and SPP RTO West, published by NETL [62] and estimated using the public tools CO₂ Saline Storage Cost Model (the storage cost model has a geologic database that includes 314 storage reservoirs, and the centroid of each reservoir is assumed to be the location of storage operations for that reservoir. Other inputs of that model include costs of technology needed to comply with EPA regulations for Class VI injection wells and monitoring and reporting requirements under the Greenhouse Gas Reporting Rule under the Clean Air Act. Storage costs are based on a reservoir’s geological characteristics (e.g., porosity and permeability), the distance from the source to the most cost-effective storage reservoir, and the annual CO₂ mass flow) [63] and CO₂ Transport Cost Model (the transport model has pipeline databases that dedicated pipeline or trunk pipeline modeling, diameter and length parameters, and pressure requirements of 2200 pounds at source (CO₂ is in a dense phase liquid state at this pressure and at pipeline specifications for purity, which is desirable for transportation) and cost and energy requirements, among others) [64].

Table 3. T&S costs for use in NETL energy system studies.

Plant Location	Basin	T&S Cost * [2018 USD/ton]	CO2 Storage Potential for T&S < USD 100/ton (Gt)
Midwest, Illinois Basin (used in this study)	Illinois	10	250
Texas, East Texas Basin	East Texas	11	90
North Dakota, Williston Basin	Williston	15	530
Montana, Powder River Basin	Powder River	22	150

* First-year break-even cost, rounded to the nearest whole, real dollar in 2018 USD per metric ton.

presents the T&S cost of CO₂ pipeline T&S for projects injected in four basins across the United States (2018 USD/ton), and Figure 13 shows these four basins. This study used the Illinois Basin in the Midwest as its reference cost point.

The total CO₂ storage potential for break-even prices lower than USD 100/ton in the Illinois basin is 250 Gt.

4. Results

The maximum decarbonization rate that was possible before an exponential spike in TSC was 98.8% for MISO-N. It was kept equal in SPP RTO West for consistency. All cases studied achieved 98.8% decarbonization relative to the 2019 level. Nevertheless, total capacity and TSCs are significantly higher under Pathway A (when deploying VRE only: Cases 1–2) than under Pathway B (when deploying both CCS and VRE: Cases 3–4), as shown in

Table 4. Comparison of the resulting capacity expansion, range of TSC, and avoided emissions under Pathway A and Pathway B for MISO-N and SPP RTO West.

	BAU	Pathway A “VRE Centered”	Pathway B “CCS Centered”
MISO-N Capacity, TSC *, and avoided emissions over 30 years	130 GW USD 228 B	579–1187 GW USD 1279 B–3878 B 7937 M tons CO2 avoided USD 124–489/ton CO2 avoided	200–201 GW USD 509 B–910 B 7936 M tons CO2 avoided USD 64–114/ton CO2 avoided
SPP RTO West Capacity, TSC *, and avoided emissions over 30 years	24 GW USD 31 B	150–161 GW USD 230 B–510 B 921 M tons CO2 avoided USD 248–552/ton avoided	33 GW USD 70 B–153 B 920 M tons CO2 avoided USD 74–164/ton avoided

* TSCs are the NPV of all costs (TOC, T&D, FOM, VOM, FUEL, and OTHER) over 30 years. The BAU TSC refers to the 2019 system operating for 30 years with TOC = 0, T&D = 0, and OTHER = 0. See the Methods section for more details.

. The cost differences are due to the total capacity retirements and additions of FE power technologies (Coal ST, NGCC, NG ST, and FE-CT/IC), VRE technologies (utility-scale PV and wind), and ES. All other technologies (nuclear, hydro, pumped hydro storage, biofuel-fired, geothermal, and “other” power generation technologies) remain unchanged and equal to 2019 capacity levels, and their costs are kept constant across all cases. The TSC is estimated as the NPV of all costs incurred under each pathway, including the TOC of the capacity expansion and all the costs associated with the operation of the system—T&D, FOM, VOM, FUEL, and OTHER—for a 30-year period. Table 4 shows that Pathway A for MISO-N results in a system of at least 579 GW, and its TSCs are equal to at least USD 1279 B. Under Pathway B, MISO-N results in a 200 GW system with TSC equal to, at most, USD 905 B. For SPP RTO West, Pathway A total installed capacity and TSCs are at least 150 GW and USD 243 B, respectively, and Pathway B’s total installed capacity and TSCs are, at most, 33 GW and USD 151 B, respectively. The BAU refers to the 2019 system operating for 30 years with TOC = 0, T&D = 0, and OTHER = 0.

The remainder of this section covers the results in terms of total capacity installed and provides a description of the results in terms of TSCs.

4.1. Total Capacity Results in MISO-N and SPP RTO West

The capacity mix required to meet the hourly load over the entire year under the prescribed decarbonization rate of 98.8% for all the cases is compared to the BAU (2019 system) for MISO-N and SPP RTO West in Figure 14 and Figure 15, respectively (see Appendix A,

Table A3. Capacity expansion results in a 98.8% decarbonized MISO-N.

MISO-N	BAU GW	GWh	Case 1 GW	GWh	Case 2 GW	GWh	Case 3 GW	GWh	Case 4 GW	GWh
Total supply resources	129.6	464,894	1187.2	549,406	758.6	547,731	199.8	549,406	200.6	551,288
Increase Factor (growth %)	1.0		9.2 (816%)		5.9 (486%)		1.5 (54%)		1.5 (55%)
Biomass	1.0	4305	1.0	4305	1.0	4305	1.0	4305	1.0	4305
Coal	46.5	243,122	0.0	0	0.0	0	0.0	0	0.0	0
Coal w/CCS (retrofit 99% capture)	0.0	0	0.0	0	0.0	0	0.0	0	30.9	87,649
NGCC and ST Gas	19.2	69,856	9.2	5598	9.2	5598	0.0	0	0.0	0
NGCC CCS (retrofit 97% capture)	0.0	0	0.0	0	0.0	0	16.7	37,482	16.7	89,864
NGCC CCS (greenfield 97% capture)	0.0	0	0.0	0	0.0	0	67.6	151,852	37.5	13,612
CT/IC Gas/Oil	23.9	2000	9.8	2000	9.8	2000	9.8	2000	9.8	2000
Hydro	1.7	5811	1.7	5811	1.7	5811	1.7	5811	1.7	5811
Pump Hydro Storage	2.7	2133	2.7	2133	2.7	2133	2.7	2133	2.7	2133
Nuclear	7.8	64,195	7.8	64,195	7.8	64,195	7.8	64,195	7.8	64,195
Other	0.3	213	0.3	2133	0.3	2133	0.3	2133	0.3	2133
Solar	1.4	1882	72.3	11,954	32.8	11,911	5.5	7209	5.5	7211
Wind	20.6	70,986	1077.9	450,886	488.8	449,253	82.2	271,895	82.2	271,983
Geothermal	0.1	392	0.1	392	0.1	392	0.1	392	0.1	392
Energy Storage	0.0	0	0.0	0		200	0.0	0	0.0	0
Interruptible Loads	4.4	0	4.4	0	4.4	0	4.4	0	4.4	0
Net Imports		40,066		40,066		40,066		40,066		40,066
Load		504,960		589,473		587,797		589,473		591,355

and

Table A4. Capacity expansion results in a 98.8% decarbonized SPP RTO West.

SPP RTO West	BAU GW	GWh	Case 1 GW	GWh	Case 2 GW	GWh	Case 3 GW	GWh	Case 4 GW	GWh
Total supply resources	24.5	66,477	160.9	75,644	150.2	75,643	32.7	75,644	32.7	75,644
Increase Factor (Growth %)	1.0		6.6 (558%)		6.1 (514%)		1.3 (33%)		1.3 (33%)
Biomass	0.0	226	0.0	226	0.0	226	0.0	226	0.0	226
Coal	6.1	30,205	0.0	0	0.0	0	0.0	0	0.0	0
Coal w/CCS (retrofit 99% capture)	0.0	0	0.0	0	0.0	0	0.0	0	4.7	5803
NGCC and ST Gas	3.9	7346	2.7	576	2.7	576	0.0	0	0.0	0
NGCC CCS (retrofit 97% capture)	0.0	0	0.0	0	0.0	0	3.4	16,223	3.4	16,223
NGCC CCS (greenfield 97% capture)	0.0	0	0.0	0	0.0	0	7.9	5916	3.2	113
CT/IC Gas/Oil	3.8	206	0.7	206	0.7	206	0.7	206	0.7	206
Hydro	3.7	11,888	3.7	11,888	3.7	11,888	3.7	11,888	3.7	11,888
Pump Hydro Storage	0.6	855	0.6	855	0.6	855	0.6	855	0.6	855
Nuclear	0.0	0	0.0	0	0.0	0	0.0	0	0.0	0
Other	0.0	51	0.0	855	0.0	855	0.0	855	0.0	855
Solar	1.2	2143	29.6	8353	25.6	8353	3.1	5399	3.1	5399
Wind	4.9	13,499	123.4	52,626	106.7	52,626	13.0	34,017	13.0	34,017
Geothermal	0.0	59	0.0	59	0.0	59	0.0	59	0.0	59
Energy Storage	0.0	0	0.0	0		10	0.0	0	0.0	0
Interruptible Loads	0.2	0	0.2	0	0.2	0	0.2	0	0.2	0
Net Imports		0		0		0		0		0
Load		66,477		75,644		75,643		75,644		75,644

for more details). All the cases require significant deployment of capacity, but for both regions, Pathway A (Cases 1 and 2) requires 3–6.5 times higher total capacity relative to Pathway B (Cases 3 and 4).

In MISO-N, the total installed capacity required for Cases 1 and 2 is at least 9 and 4 times larger than the BAU, respectively, while total capacities that are 1.5 times larger than the BAU are warranted by Cases 3 and 4. In fact, Case 1 (VRE) of MISO-N results in a system with an installed capacity of 1.18 TW, higher than the total existing summer power capacity of the full continental United States (approx. 1.14 TW in 2019 [55]). MISO-N currently accounts for 11% of U.S. power capacity. The large increases in capacity in VRE Case 1 are mainly due to the applied constraint of meeting the electricity demand every hour without any loss of load at the desired high decarbonization rates. The effective load-carrying capacity of each additional unit of VRE resource installed decreases dramatically as the VRE capacities begin to exceed the baseload firm capacity. At the higher VRE penetrations required for the high decarbonization rates, in lieu of any supporting dispatching capacity, installation of additional VRE capacity, albeit with diminishing returns, is the only avenue to increase generation to meet the load. The introduction of ES under Case 2 nearly halves the required MISO-N capacity relative to Case 1, from 1.18 TW to 0.58 TW. Even so, this is equivalent to more than twice the size of MISO-N under Pathway B (Case 3 or 4), four times the size of today’s MISO-N system, and almost half (47%) of today’s U.S. total capacity installed. The projected installation rate for the VRE Cases 1 and 2, between 39 and 79 GW per year MISO-N, for example, is of the same order of magnitude as the ~54 GW of VRE installations reported in 2023 for the entire United States [65]; however, sustained installation at this rate is subject to significant uncertainties in the continued availability of the current promotional subsidies for VRE installation along with the establishment of a market design to support the capital investments. Further, whether such a high VRE capacity expansion can be accommodated in terms of land, mineral, and transmission resources is debatable. The total land resource necessary to accommodate VRE additions under Pathway A would be at least 103,000 square miles (assumptions: Under Case 1, approximately 102,000 square miles are necessary to accommodate 300,000 wind turbines or 1.1 TW of nameplate capacity (each turbine of 3 MW, representing the 2021 U.S. average wind turbine size). Additionally, approx. 1230 square miles are necessary to accommodate 72 GW of utility-scale solar PV (assuming 8 acres per MW_AC)) (more than 11% of total MISO-N territory) using land requirements from [66,67]. The interconnection will take approximately 80 years if the pace is similar to the level of additions seen in the United States in 2021. The continued availability of critical minerals required to build the VRE plants is also subject to significant uncertainties due to global and national supply chain limitations. Thus, the significant land resources, the current transmission investments and interconnection procedures, and the availability of critical mineral resources would dictate the actual feasibility of this level of deployment. A detailed discussion of these implications is beyond the scope of the present manuscript.

There is not a significant capacity difference between Cases 3 and 4 in Pathway B. Under Pathway B, the system’s capacity is approximately 0.2 TW for Cases 3 and 4. This corresponds to less than 20% (17.5%) of today’s U.S. total capacity installed. MISO has published the MISO Futures Study [12], which includes a deep decarbonization future with an 81% decarbonization rate achieved by 2039 (Future 3) under which CCS is included. The amount of NGCC+CCS is in the same order of magnitude (about 42 GW is projected in the MISO Futures Study vis a vis the 67.6 GW estimated in this analysis), but Future 3 total capacity is 365 GW, about 50% higher than Cases 3 and 4. Also, total net expansion (additions minus retirements) is much higher in Future 3 (200 GW) than in Cases 3 and 4 (70 GW), with a lower decarbonization goal. This may be due to the load increase assumed in Future 3, both in level and shape, which can be more challenging than the load assumption presented in this analysis, as well as potential constraints imposed on maximum capacity additions per technology. Other differences with the MISO Futures Study are that the capacity retirements and additions are modeled for most of the existing technologies and are not limited to VRE, ES, and FE-fired units, unlike the present analysis.

In SPP RTO West, Cases 1 and 2 result in a system installed capacity that is at least 6 and 5 times larger than the BAU, respectively, and Cases 3 and 4 result in a system capacity that is 1.3 times larger than the BAU. Within Pathway A, there is a significant capacity difference between Case 1 and Case 2, almost the equivalent capacity of one full 2019 system. The introduction of ES under Case 2 reduces the system’s capacity by 20,000 MW compared to Case 1, from 161,000 MW to 141,000 MW. Still, this is equivalent to more than 4 times the size of the system capacity under Pathway B (Case 3 or 4) and 5.5 times the size of today’s SPP RTO West system capacity. Under Pathway B, the system capacity is approximately 33,000 MW for both Cases 3 and 4.

In terms of technology type for both regions, Pathway A has the lowest technology diversity. Although all cases have new VRE deployed, Pathway A (Cases 1 and 2) mostly comprises VRE, with a share in terms of capacity installed of at least 93% and 94% (Case 2 in MISO-N and SPP RTO West, respectively) and as high as 95% and 97% (Case 1 of SPP and MISO-N, respectively). Under Pathway B (Cases 3 and 4), the resulting system is significantly more diverse. VRE consists of 44% of the MISO-N system capacity and 49% of the SPP system capacity—still much higher than today’s 17% and 25% in MISO-N and SPP RTO West, respectively. The share remaining comprises all other technologies—including FE fired with CCS, FE without CCS, and all other technologies—accounting for 43, 5, and 9%, respectively, in MISO-N.

In the case of MISO-N, the demand for power has a moderate growth, approximately 1.1 to 1.2 times the 2019 load (non-coincident peak load increases only 10%, to 101 GW, and total annual energy demand increases 17%, to 590,000 GWh, compared to BAU (2019)), not unlike the case of SPP RTO West, where the demand for power in 2035 is projected to be 1.1 times that of the corresponding 2019 load. (Non-coincident peak load increases by 7%, from 14 GW to 15 GW, and total annual energy demand increases by 14%, from 66,500 GWh to 75,600 GWh, compared to BAU (2019).) Accordingly, the difference in the amount and type of capacity deployments required to guarantee resource adequacy and achieve 98.8% decarbonization for the two regions is mainly attributable to the differences in load-carrying capability of the different generating units. For MISO-N, this translates to Pathway A deploying at least 5.5 MW installed per MW of future peak demand (Case 2) and as much as 11.8 MW installed per MW of future peak demand (Case 1), and for SPP RTO West, 9.3 MW per MW of future peak demand (Case 2) and as much as 10.7 MW (Case 1). Pathway B results in 2 MW installed per future peak MW (Cases 3 and 4) in MISO-N and 2.2 MW installed per future peak MW in SPP RTO West.

4.2. FE Retirements and Remaining FE Units

Table 5. FE retirements under Cases 1–4 for both regions.

	Retirements in MISO-N	Retirements in SPP RTO West
Pathway A: FE-ST Coal, FE-NGCC and ST Gas, * and most of FE-CT/IC * retire and VRE replaces them (98.8% decarbonization)	Cases 1–2: 46.5 GW of coal (100%), 10 GW of NGCC+ST gas (55%), 14.1 GW of CT/IC gas/oil (60%), for a total of 70.6 GW (79% of all FE-fueled power plants in 2019)	Cases 1–2: 6.1 GW of coal (100%), 1.2 GW of NGCC+ST gas (30%), 3.1 GW of CT/IC gas/oil (82%), for a total of 10.4 GW (76% of all FE-fueled power plants in 2019)
Pathway B: Most of FE-CT/IC * retires, FE-NGCC and ST Gas are retrofitted with CCUS, while ST Coal retires in Case 3, and both FE-NGCC and ST Gas and FE-ST Coal are retrofitted in Case 4 (98.8% decarbonization)	Case 3: 46.5 GW of coal (100%), 14.1 GW of CT/IC gas/oil (60%), for a total of 60.6 GW (68% of all FE-fueled power plants) Case 4: 14 GW of CT/IC gas/oil (60%), for a total of 14 GW (16% of all FE-fueled power plants in 2019)	Case 3: 6.1 GW of coal (100%), 3.1 GW of CT/IC gas/oil (82%), for a total of 9.3 GW (67% of all FE-fueled power plants). Case 4: 3.1 GW of CT/IC gas/oil (82%), for a total of 3.1 GW (23% of all FE-fueled power plants in 2019)

* Some FE power plants do not retire. In Pathway A, the unretired FE power plants balance the high VRE penetration. In Pathway B, eligible FE is retrofitted with CCS (in Case 3, coal is not retrofitted and retires; in Case 4, coal is also retrofitted with CCS). For more details, see Table A3 and Table A4 in Appendix A.

summarizes the FE-fired power retirements under Cases 1 and 2 (Pathway A) and Cases 3 and 4 (Pathway B). In both regions, a significant share of FE-fired power plants is retired. In MISO-N, 79% of FE-fired power plants retire in Pathway A. In Pathway B, the total number of FE-fired power plants that retire depends on which ones can technically retrofit with CCS. In Case 3, 68% of all FE-fired power plants are projected to retire. In Case 4, coal power plants are also retrofitted with CCS, which leads to only 16% of all FE-fired power plants retiring. The retirements correspond to FE-fired units that cannot retrofit with CCS. In SPP RTO West, 76% of FE-fired power plants retire in Pathway A. In Pathway B, 67% of all FE-fired power plants still retire under Case 3 and 23% under Case 4.

Table A5. Source of remaining CO₂ emissions in the decarbonized MISO-N and SPP RTO West systems.

Pathways	MISO-N	SPP RTO West
Pathway A “VRE-Centered” Case 1: VRE Case 2: VRE+ES	Cases 1–2 10 GW of CT/IC gas/oil, 9 GW of NGCC/ST gas	Cases 1–2: 2.7 GW of NGCC/ST gas, 0.7 GW of CT/IC gas/oil
Pathway B “CCS-Centered” Case 3: NGCC+CCS Case 4: NGCC&Coal+CCS	Case 3: 10 GW of CT/IC gas/oil; 3% unabated emissions of 19 GW of retrofitted NGCC+ST Gas units with CCS; and 3% unabated emissions of 67.5 GW of greenfield NGCC + ST Gas units with CCS. Case 4: 10 GW of CT/IC gas/oil; 3% unabated emissions of 19 GW of retrofitted NGCC+ST Gas units with CCS; 3% unabated emissions of 37.5 GW of greenfield NGCC + ST Gas units with CCS; and 1% unabated emissions of 46 GW of ST Coal retrofitted with CCS.	Case 3: 0.7 GW of CT/IC gas/oil; 3% unabated emissions of 3.9 GW of NGCC+ST Gas units with CCS; and 7.9 GW of greenfield NGCC+ST Gas units with CCS. Case 4: 0.7 GW of CT/IC gas/oil; 3% unabated emissions of 3.9 GW of NGCC+ST Gas units with CCS; 3% unabated emissions of 3.2 GW of greenfield NGCC+ST Gas units; and 1% unabated emissions of 6.1 GW of ST Coal retrofitted with CCS.

in Appendix A lists the FE units that remain operating in the system, which corresponds to the source of remaining CO₂ emissions in MISO-N and SPP RTO West during the 30 years of operation of the decarbonized systems.

4.3. CCS Retrofits in Both Regions Under Pathway B

Retrofitting existing FE units with CCS presents a significant potential to reduce emissions while continuing to use existing infrastructure.

Table 6. Total pre-retrofit annual CO₂ emissions, captured emissions, and post-retrofit annual CO₂ emissions in the regions under Pathway B (Cases 3 and 4).

Region and Fuel	Capacity	Pre-Retrofit Annual CO2 Emissions, Thousand Tons per Yr. (per Unit *)	Total Parasitic Retrofit Load, MW (per Unit *)	Total CO2 Captured, Thousand Tons per Yr. (per Unit *)	Post-Retrofit Annual CO2 Emissions, Thousand Tons per Yr.
MISO-N coal	49,653	257,858 (2262)	15,850 (297)	255,279 (2239)	2579 (23)
MISO-N NG	17,080	36,802 (944)	2543 (65)	35,698 (915)	1104 (28)
SPP RTO West Coal	5590	36,172 (2010)	1775 (99)	35,810 (1989)	362 (20)
SPP RTO West NG	4335	7542 (502)	690 (46)	7315 (488)	226 (15)

* Average per unit modeled at pre-retrofit average capacity factor.

shows the modeled retrofits for the two regions with a post-combustion CCS auxiliary plant system. CCS capture rates are 99 and 97% for steam turbine coal power plants and natural gas-fired power plants, respectively.

MISO-N (2019) has almost 50,000 MW of coal-fired power plants (ST units) and 17,000 MW of NG-fired power plants (CC + ST units), for a total of approximately 67,000 MW FE-fired capacity considered for CCS retrofits. After retrofits, the net rated capacity of these units decreases by 18,400 MW, equal to the parasitic load associated with the power and heat requirements of the CCS technology. The total pre-retrofitted annual CO₂ emissions are approximately 300 M tons per year, which are cut to less than 4 M tons per year after the CCS retrofit.

SPP RTO West (2019) has 5600 MW of coal-fired power plants (ST units) and 4300 MW of NG-fired power plants (CC + ST units), for a total of approximately 10,000 MW capacity considered for CCS retrofits. After retrofits, the net capacity decreases by 2500 MW, equal to the parasitic load associated with the power and heat requirements of the CCS technology. The total pre-retrofitted annual CO₂ emissions are approximately 43.5 M tons per year. After retrofitting the units with CCS, the total annual emissions are less than 0.6 M tons per year.

4.4. Total Costs Results

Figure 16 and Figure 17 show costs of MISO-N and SPP, respectively. Cost comparisons are presented across the BAU and Cases 1–4, showing (a) TOC and annual costs, (b) detailed annual costs, and (c) TSC.

Considering results for both regions, Pathway A’s TOC is at least 2 to 11 times higher than the TOC of Pathway B. (In MISO-N, Pathway A’s minimum TOC is over Pathway B’s max TOC = USD 969,000 M/USD 430,000 M = 2.3; Pathway A’s max TOC is over Pathway B’s min TOC = USD 2,900,000 M/USD 257,000 M = 11.3. Similarly, in SPP RTO West, these factors are 3.3 and 11.3, respectively.) The minimum savings achieved when CCS is included is USD 540 B, which corresponds to the difference between the lowest TOC of Pathway A and the highest TOC of Pathway B.

Similar to TOC, annual costs (FOM+VOM+FUEL+OTHER+T&D) are higher for the cases under Pathway A than for the cases under Pathway B, but the differences between the two pathways are less marked than the TOC disparity. All cases have annual costs that are about the same order of magnitude, ranging from approximately USD 16 to 63 B for MISO-N and USD 2 to 10 B for SPP RTO West. The annual costs are higher than the annual costs of the non-decarbonized systems for a moderate load increase. Annual costs of the BAU are USD 15 B for MISO-N (this estimate for MISO-N is in line with S&P-estimated annual costs of the full MISO region. According to S&P data, in 2019, MISO’s FOM, VOM, and FUEL costs were USD 18.7 B. MISO-N capacity is approximately 2/3 of the total capacity of MISO. MISO and MISO-N refer only to the U.S. footprint of the full MISO) and USD 2 B for SPP RTO West, including FOM, VOM, and FUEL. Within Pathway A, annual costs are USD 27–46 B per year in MISO-N and USD 5–6 B per year in SPP RTO West. Within Pathway B, Case 4 has slightly higher annual costs than Case 3, equal to approximately USD 20–23 B per year (Cases 3 and 4) in MISO-N and USD 2.8–3.2 B per year (Cases 3 and 4) in SPP RTO West. This is due to higher FOM costs—more than double—of retrofitted coal power plants with CCS that are part of Case 4 and not of Case 3, compared with retrofitted NG power plants with CCS (see Figure 11).

From all annual costs, FOM is the most significant cost for Cases 1 and 2, accounting for 77–86% of annual costs in MISO-N and 84–85% of annual costs in SPP RTO West. VREs FOM per kW are lower than most of the other technologies (see Figure 11), but due to the enormous amount of added VRE capacity in Cases 1 and 2, total FOM costs are the highest for Case 1. For Cases 3 and 4, both FOM and fuel costs share the same importance: in MISO-N, FOM costs represent 39–44% and fuel costs represent approximately 31–35% of total annual costs. In SPP RTO West, FOM costs represent 42–48% and fuel costs represent approximately 26–31% of total annual costs. T&D and OTHER are the least significant costs of the annual costs for both regions. In Pathway A, T&D represents the additional transmission lines needed to accommodate the added capacity. On a MWh basis, T&D costs as shown in Figure 11 are equal to USD 7/MWh, USD 6/MWh, and USD 1/MWh, respectively, for solar PV, wind, and greenfield NG-fired power plants with CCS. The retrofitted power plants have zero T&D costs, as they are already in operation using existing infrastructure. This leads to T&D costs of approximately USD 2.3 B and USD 1.3 B for pathways A and B, respectively, in MISO-N. In SPP RTO West, T&D costs are USD 278 M and USD 146–149 M for Pathways A and B, respectively. OTHER costs include balancing or integration costs associated with high VRE penetrations, equal to USD 5/MWh for wind and solar PV, and T&S of CO₂ equal to USD 10/ton. In MISO-N, OTHER is USD 1.8–2.4 B, and in SPP, OTHER is USD 210–247 M across all cases.

Total annual costs estimated do not include the social cost of carbon (SCC), as shown in Equation (2), due to the low level of emissions for Cases 1–4 and the fact that all cases are set to achieve the same decarbonization level, which would not drive any additional difference between both pathways for the 30 years considered. The BAU, the system as it is today, is the only case that would see a total SCC that can be compared with other system costs, justifying the need to invest in decarbonization strategies. The SCC is highly uncertain, with ranges suggested by the EPA of USD 155 –200/ton for the period 2035–2050 (corresponding to a 2.5% discount rate) [68].

TSCs for MISO-N are at least USD 1279 B and at most USD 910 B under Pathways A and B, respectively. For SPP RTO West, Pathway A TSCs are at least USD 230 B, and Pathway B TSCs are at most USD 153 B. Pathway A TSCs are 1.4–8 times larger than Pathway B TSCs. On a MW basis, Figure 18 shows TSC per MW for Cases 1–4 in both regions. MISO-N TSC per MW is USD 1.6–3.3 M under Case 1 versus USD 2.5–4.5 M under Cases 3 and 4. In SPP RTO West, TSC per MW is USD 1.6 M–USD 3.2 M under Case 1 versus USD 2.1–4.7 M under Cases 3 and 4. Decarbonizing MISO-N is more financially intensive than SPP RTO West for all cases and ranges, except for the upper bound of Cases 3 and 4. For both regions, Case 1 is the least expensive across all cases on a per-MW basis. The VRE-centered pathway can be less expensive on a per-MW basis than the CCS-centered pathway. When storage is added (Case 2), the TSC per MW increases to USD 1.7 M–3.7 M in MISO-N and USD 1.6 M–3.3 M in SPP RTO West. The differences between both regions in Case 2 are a consequence of the balancing role of ES to VRE, which is particular to the load profile of the region and the generation mix. For MISO-N, ES contributes significantly to balancing VRE. Adding ES reduces the need for capacity deployment in Case 2 to almost half compared to Case 1, but the total system costs of the expansion are almost the same in Case 2 and Case 1 due to the cost of ES technologies. This results in a TSC that is similar to Case 1—and a much smaller expansion—that leads to USD 2.3 M per MW installed. For SPP RTO West, adding ES results in a slightly more expensive system overall but does not significantly reduce the capacity additions seen in Case 1, which leads to USD 2 M per MW installed. This analysis considers various ES technologies, but it is limited to 10 h duration technologies. (The 10 h duration ES technologies included in the TOC range used in this analysis are Li-ion phosphate (LFP), Li-ion nickel manganese cobalt, lead acid, vanadium redox flow, compressed air energy storage, pumped storage hydropower hydrogen. The capacity varies by technology, with a range of 1–100 MW.) A more detailed analysis that optimizes the choice of ES duration technologies based on the system needs is beyond the scope of this analysis and can illuminate the role of ES in decarbonizing these systems. Because the amount of capacity to be deployed under Pathway A is considerably higher than under Pathway B, TSC per MW as an indicator of a cost-effective pathway can be misleading. In the long run, and constrained to maintaining resource adequacy, including CCS in the capacity expansion yields lower TSC for the same decarbonization level than deploying only VRE+ES.

4.5. Emissions and Cost-Effectiveness

Figure 19 shows the total emissions avoided through the 30-year period for both regions. Total emissions are 7937 M tons and 921 M tons of CO₂ avoided in MISO-N and SPP RTWO West, respectively. Pathway A meets this emission reduction without incurring T&S of CO₂ costs, while Pathway B requires a buildup of infrastructure for T&S of CO₂. Under Pathway B, almost all the avoided emissions come from CCS-captured CO₂ of retrofitted or greenfield fossil power plants. Annually, MISO-N sends to T&S a total of 226 and 236 M tons (under Cases 4 and 3, respectively), equivalent during a 30-year period to a total of 6772–7085 M tons or 77–80% of emitted CO₂ under the BAU. This is shown in Figure 18.

The cost component “OTHER” includes costs associated with CO₂ T&S for CCS deployment. “OTHER” is USD 1.8–2.4 B and USD 210–247 M, in MISO-N and SPP RTO West, respectively, across all Cases 1–4. This same range applies to Cases 3–4 particularly. Cases 1–2 show “OTHER” costs equal to USD 2.1 B for MISO-N and USD 240 M for SPP RTO West. In other words, the T&S costs of CO₂ of Cases 3–4 are comparable to the balancing costs associated with high penetration of VRE resources of Cases 1–2. The MISO-N and SPP RTO West regions have available geological storage in place that can meet these CO₂ storage requirements. The total CO₂ storage potential for break-even prices lower than USD 100/ton in the Illinois Basin is 250,000 M tons (see Section 3, Data), which could store 33 times the cumulative 7700 M tons of MISO-N and SPP RTO West combined, or a total of almost 1000 years (33 × 30 years).

The cost per ton avoided, estimated as the TSC over the cumulative emissions avoided over 30 years, compared to 2019 levels is shown in Figure 20. Pathway B is more cost-effective than Pathway A. The decarbonized systems emit approximately 3.2 M tons/year in MISO-N and 1.2 M tons/year in SPP RTO West. Cumulative avoided emissions during the 30-year period are approximately 7936 M tons and 921 M tons for MISO-N and SPP RTO West, respectively. (The estimates presented do not intend to represent the detailed emissions of the operation of the system, which require annual dispatch analysis, but serve as a point of comparison between the pathways. The emissions avoided in the period 2020–2035 were not included due to the sensitivity of the results to assumptions on changes in the generation mix, i.e., the assumed schedule of retirements and capacity additions.) For MISO-N, Pathway A yields a cost of USD 161–489/ton avoided, and Pathway B yields a cost of USD 64–114/ton avoided. For SPP RTO West, Pathway A yields USD 264–590/ton avoided, and Pathway B yields USD 74–164/ton avoided during the 30-year period. For MISO-N, Pathway A is 1.4–7.7 times more expensive (per ton avoided) than Pathway B. For SPP RTO West, Pathway A yields a cost of avoided ton 1.6–8 times higher than Pathway B. (In MISO-N, Pathway A TSCs are USD 1279–3878 B. Pathway B TSCs are USD 504–905 B. The min Pathway A and max Pathway B values result in 1.4, and the opposite values result in 7.7. In SPP RTO West, Pathway A TSCs are USD 243 M–544 B and Pathway B TSCs are USD 68–151 B. Pathway A is 1.6–8 times larger than Pathway B.)

4.6. Limitations and Further Work

Some of the limitations of this study include the limited number of scenarios. The number of pathways and cases, and the number of technologies chosen through a “what if” analysis approach, or case-based approach, as opposed to an optimization algorithm, which restricts the number of solutions. The pathways are chosen as bounding extremes, as an envelope of other alternative mid-way scenarios such as reaching 80% decarbonization instead of 100%. The results of this analysis are limited to the initial technology choices and the introduction of only one additional technology (CCS). For instance, other advanced power technologies (such as modular nuclear reactors, hydrogen plants, geothermal or biomass with CCS) and carbon dioxide removal technologies (such as Direct Air Capture) are not included in the technology choices available. Although all these technologies are being investigated to support regional and national clean energy pathways, and are discussed in the literature [69,70], the research question behind this analysis was more narrowly defined. This simplicity allows us to make robust conclusions on the cost-effectiveness of the introduction of CCS at the system level. The goal of this analysis is to measure the impact of the addition of CCS as the difference between Pathway A and B, which has been achieved.

Total costs include T&S costs of CO₂ (see Section 2, Methods (${OTHER}_{tech}$ represents other costs; for wind and solar PV, these costs are additional balancing costs, in addition to construction of new transmission capacity, and are reported by the literature as costs associated with new flexible capacity or additional balancing reserves requirements, estimated as the multiplication of costs per MWh and total generation (MWh). For FE-fired power plants, these costs include the T&S cost of CO₂ (USD/ton) translated in a per-MWh value and multiplied by total generation (MWh)), for more details) that use an average Midwest value, as opposed to a more tailored estimate. This limitation is present due to the scope of this analysis. A CCS transport and storage potential for MISO-N and SPP RTO West with higher resolution may provide another mid-point estimate, but given that the role of OTHER costs in annual costs is relatively small (USD 2 B and USD 0.2 B in MISO-N and SPP RTO West, respectively, or between 3 and 8% of annual costs), there are few additional insights that could be drawn with a more detailed T&S estimate under the scope of this paper. Lastly, this analysis is not intended to comment on the public acceptance of CCS or the feasibility of large-scale deployment of the technology based on its public acceptance.

This paper also does not intend to comment on the economic viability and sustainability of the hypothetical decarbonized system. Markets are constantly evolving as flaws, needs, and shortcomings are identified. Recent examples of evolution include the introduction of ramp capability products in California, PJM, and MISO to incentivize previously uncompensated generation flexibility. Using today’s market mechanisms, the sustainability of future systems is likely unattractive from a simple capital recovery perspective, as recovery periods would likely exceed asset design life. A particular example to illustrate this is the recovery of a new, subsidized wind generator. For the CAPEX (USD 1200–2300/kW or USD 1.2 M–2.3 M per MW) used in this paper, a period of 30 years would be required to reach recovery through capacity revenues forecast by S&P Global/IHS in their December 2023 North American Power Analytics Planning Case [71] with additional energy market revenues suppressed by the zero short-run marginal cost of renewable resources.

5. Conclusions

This paper explores the substantial system-level cost gains that can be realized from diversifying capacity expansion plans that consider all carbon mitigation strategies, including CCS, over a 30-year horizon. The results shed light on the long-term implications of early planning decisions around CCS deployment at a sub-national level.

Deep decarbonization of two RTOs—MISO-N and SPP RTO West—is possible under a moderate demand increase of 16–17% in terms of today’s (2019) total annual energy demand and 10% in terms of non-coincident peak load and under no deployment constraints (such as land, water, and interconnection permits, among others) via a VRE-centered pathway (Pathway A) or a CCS-centered pathway (Pathway B). The differences in total capacity installed, TSC, and USD/ton-avoided highlight the need for clean firm energy to attain deep decarbonization.

Reducing carbon emissions by 98.8% compared to 2019 emissions can be achieved via Pathway A (Cases 1 and 2) by retiring FE-fired units and installing wind and solar PV (Case 1) and wind, solar PV, and energy storage power capacity (Case 2), or via Pathway B (Cases 3 and 4) by prioritizing the retrofit of the existing NGCC and ST Gas units with post-combustion CCS, retiring (Case 3) or retrofitting (Case 4) all ST Coal units with CCS and adding wind and solar power capacity. Pathway A projects that installed generation capacity would grow from present levels of around 130 GW and 24 GW in MISO-N and SPP RTO West, respectively, to an outstanding 579–1187 GW and 150–161 GW in MISO-N and SPP RTO West, respectively, equivalent to 4 to 10 times the capacity of today’s systems. A much more moderate growth, equal to 1.3–1.5 times the capacity of today’s system is possible under Pathway B. Similarly, Pathway A has much higher TSCs than Pathway B. The TSCs of Pathway A are 1.4–8 times larger than the TSCs of Pathway B. The results indicate that it is more cost-effective (in USD/ton-avoided) to include CCS technologies than to not include them in the decarbonization strategy over 30 years of operation of the systems. When CCS is not included (Pathway A), the cost per ton avoided is USD 124–489/ton in MISO-N and USD 248–552/ton in SPP RTO West. When CCS is included, the cost per ton avoided decreases by 29–87%, equal to USD 64–114/ton in MISO-N and USD 74–164/ton in SPP RTO West.

The large differences in costs and capacity deployed between pathways A and B show that technology choices matter. CCS is a technology that provides cost-effective carbon emission reductions in the power systems modeled. In the long run, CCS can greatly contribute to attaining deep decarbonization of an RTO, even if TOC costs on a MW basis are higher than solar PV, wind, or, in some cases, ES. CCS enables existing dispatchable FE-fired units, which can provide firm power at high-capacity factors, to continue to operate in the system while substantially reducing their carbon emissions.

These results are conservative when contextualized. This study does not consider capacity expansion requirements to meet extreme weather events, the sensitivity of the results to high natural gas prices, low coincident solar and wind events, or high electrification scenarios. It also does not include physical considerations such as regional suitability, land availability, or limitations to the construction of transmission infrastructure for the deployment of solar and wind. (For example, MISO-N would need to expand significantly under Case 1. The 98.8% decarbonized system would be larger than today’s U.S. nameplate power capacity, with 1.18 TW of on-the-ground capacity. Today’s U.S. power capacity is 1.14 TW. This large power nameplate capacity would require significant land resources.) It does not include either supply chain limitations or administrative limitations, such as processing times associated with acquiring interconnection rights of new capacity that could delay or limit the expansion of the system. It does not include CCS regulatory challenges, including approval and processing times of land rights for carbon storage. Lastly, for consistency in drawing comparisons across pathways, no federal or state-level tax incentives or programs are included in this analysis.