Highlights

• Local governments across the United States have adopted ambitious decarbonization goals that rely on cost-effective clean energy procurement within wholesale electricity markets.
• Although wholesale electricity markets contain many features that provide an enabling environment for the integration of clean energy resources into the electricity grid, their evolving rules and policies can affect local governments’ ability to achieve their clean energy goals.
• Improvements to several wholesale market rules and policies can further catalyze renewable energy deployment so that local governments can meet their clean energy goals.
• Key areas for reforms within wholesale markets include transmission; energy, ancillary services, and capacity market rules; integration of new resource types; and stakeholder processes.
• Although all seven wholesale electricity markets in the United States share some commonalities across barriers to and opportunities for clean energy deployment, each market has unique characteristics and circumstances that require consideration as local governments pursue their clean energy goals.

Background

In the United States, seven wholesale electricity markets are operated by regional transmission organizations (RTOs) and independent system operators (ISOs). About two-thirds of total electricity generation occurs within these wholesale electricity markets. Further, there are large regions of the country not currently served by an RTO—including many states in the West and, to a lesser extent, the Southeast—that have recently adopted some form of a coordinated energy market, even if not a full RTO, to harness at least some benefits associated with RTOs.

The core responsibilities of an RTO, which is a nonprofit entity, include running competitive markets, providing for the least-cost dispatch of electricity, ensuring open access to transmission for energy suppliers and purchasers, and maintaining transmission grid reliability. Members of RTOs include utilities, independent power producers, renewable energy developers, large end users (such as industrial customers), and, in some cases, environmental groups. Wholesale electricity markets match generators and electricity providers (such as distribution utilities), typically through bid-based markets. RTO rules governing wholesale market operations and transmission planning (and other issues) are regulated at the federal level by the Federal Energy Regulatory Commission (FERC). Both RTO and FERC decisions and actions may impact the deployment of clean energy and the ability of local governments to meet their clean energy goals, and there are opportunities for engagement at both levels.

RTOs are generally beneficial for clean energy deployment. Wholesale markets aim to promote competition among generators and equal access to transmission, allowing lower-cost generators to enter the market and guiding investment and retirement decisions for different electric-generating units. These markets have enabled innovative financing mechanisms that have helped drive the growth of renewables (e.g., virtual power purchase agreements, or vPPAs). Additionally, regional transmission planning conducted by RTOs, although in need of reforms, provides the framework for a transparent process for projecting future grid composition and determining transmission investment needs. Areas without an RTO do not enjoy the same level of competition, access, and transparency apparent in wholesale markets.

About This Paper

This working paper is intended as a primer for local governments interested in learning more about wholesale electricity markets and the issues affecting clean energy deployment. Specifically, it examines the effect that RTO policies, rules, and practices can have on the ability of local governments to achieve their clean energy goals. It provides background on the RTO-operated wholesale electricity markets, including their mission, how they operate, and their role in clean energy deployment. This paper then identifies issues related to transmission, market-specific rules, and the stakeholder process within these RTOs that may impede or support expanded clean energy deployment.

This paper is a companion to an earlier paper that explains how local governments can engage on wholesale electricity market issues (Ratz et al. 2021). By better understanding these markets and the factors impacting renewable energy within them, local governments can more effectively leverage their power—as both large consumers of electricity and as public entities representing their communities—to engage on areas that will have consequential impacts on achievement of their local goals.

Key Findings

The design of specific market rules and transmission processes and practices can either create barriers to or opportunities for clean energy deployment. Although RTOs demonstrate enabling features for renewable generation, substantive barriers exist because markets were primarily designed for more conventional fossil fuel and nuclear plants. Barriers are related to transmission, including rules and practices for transmission cost allocation, planning, and interconnection; market participation rules and determinations of resource adequacy; and governance.

Broader participation of stakeholders, including local governments, can benefit efforts to reform wholesale market policies that reflect outdated practices or incumbent interests. RTO decision-making is often heavily influenced by entrenched interests, including incumbent generators, many of whom own conventional resources, and may reflect outdated practices that keep uneconomic fossil fueled generation in the resource mix. RTOs may struggle to adopt regulatory and market structures that adequately reflect the value of renewable generation, hybrid resources (such as solar-plus-storage installations), and distributed energy resources, which are key resources for local governments looking to decarbonize.

By better understanding the barriers to clean energy within RTOs, local governments can strategically engage at the RTO or FERC level to advance their clean energy goals. A fundamental understanding of the most important issues affecting renewable energy deployment can enable local governments to target their engagement efforts toward specific areas that significantly impact their clean energy priorities. Priority market issues for local governments may depend on how they plan to achieve their goals and the types of projects they seek to implement, which can range from distributed generation to large-scale power purchase agreements (PPAs).

For deployment of large-scale renewables, transmission access and interconnection queues can be important issues that affect renewable energy project timelines and costs. Sufficient transmission capacity, shortcomings in transmission planning, and limitations in employing technologies that improve transmission system efficiency are all concerns in many regions, and solutions can take years to implement, which is a consideration for meeting long-term goals.

For local governments focused on distributed generation, developing plans to derive value from FERC Order No. 2222 represents a significant near-term opportunity. This can be important for local governments, particularly those looking for cost-effective community-wide clean energy solutions.

Local governments have a variety of engagement pathways available to them to effect change on wholesale market issues. In determining their engagement strategy, local governments should consider which issues are highest priority, what types of action might be most effective, their desired level of effort, and whether they want to engage independently or collaborate with peers.

Wholesale electricity markets operated by RTOs and independent system operators (ISOs) cover two-thirds of electricity generation in the United States (FERC 2021c; Figure 1).¹ These markets have a significant effect on the types and cost of generation resources that power the grid. RTOs help guide investment in new electricity sources, as well as the retirement of old ones, through their core responsibilities of operating markets for energy and grid services for maintaining reliability (ancillary services), and ensuring adequate generating capacity is available to serve loads (including the operation of markets for capacity in some RTOs). They also oversee transmission planning, which is a critical issue for the efficient operation of the grid and the development of utility-scale renewable resources.

A wholesale electricity market provides for the centralized dispatch of electricity from a diverse array of resources across a wide geographic area, which optimizes the dispatch of energy and reduces the costs of integrating renewables into the grid (Bromley-Dulfano et al. 2021; Gimon et al. 2020). Customers seeking clean energy offerings for their own electricity needs can benefit from participating in these markets—even where such energy is procured through a bilateral contract—because the markets reduce the costs of integrating renewable resources, provide transparent prices and a wider suite of ancillary services (Chen 2020), and facilitate the use of innovative contracts, such as virtual power purchase agreements (vPPAs), which provide additional options for purchasing clean energy (Energy Strategies 2021; Box 2). Moreover, these resources can access transmission in the RTO without needing a specific contract path (Energy Strategies 2021), and the RTOs conduct centralized transmission planning that is essentially nonexistent in non-RTO regions (Howe et al. 2021; Pfeifenberger et al. 2021). Such planning, in theory, would fully account for the future renewable resource development pursuant to public policies. Moreover, RTOs have been found to reduce the overall cost of electricity and the total need for generation (Chen and Hartman 2021).

Recent analyses of the impacts associated with the potential creation of an RTO where one does not presently exist, such as in the Southeast or the West, have shown significant benefits for the integration of renewable resources (Energy Strategies 2021; Gimon et al. 2020). However, the design of specific market rules and transmission planning processes can also either create barriers or opportunities for clean energy deployment, which vary by region.

RTO Responsibilities and Design Features

Figure 1 | ISO/RTO Territories in the United States

Notes: ISO = independent system operator. This map illustrates where organized wholesale markets have developed in the United States by indicating the territories of the regional transmission organizations (RTOs)/ISOs that operate them. The gray areas indicate locations where a fully developed organized wholesale market does not exist. For example, this map does not include the Western Energy Imbalance Market, operated by the California ISO (CAISO), as it is not a full RTO or ISO, though it provides a limited market for utilities in California, Washington, Oregon, Idaho, Montana, Wyoming, Nevada, Utah, Colorado, Arizona, and New Mexico to exchange power.

Source: Adapted from Schneider 2019.

All RTOs dispatch and operate markets for the purchase and sale of energy and ancillary services in two phases: a day-ahead market, which schedules the commitment of resources, and a real-time dispatch, which reconciles any differences in the day-ahead market and actual demand and supply.² The RTO first dispatches the units with the lowest price offers to sell energy, and the highest offer needed to meet demand at that time sets the clearing price, which varies by location depending upon the availability of transmission to deliver energy from the resource with the lowest offer (FERC 2020). Generation owners may choose to self-schedule, whereby they are not incorporated into the RTO’s dispatch, which dispatches the lowest-cost generation available. This practice is not always problematic, but it can create inefficiencies when used by coal-fired generation, which typically must continue to operate at a minimum level of generation and cannot be easily turned on or off. Many of the plants that choose to self-schedule are owned by a utility, which will recover plant costs from ratepayers, denying utility customers the benefits of obtaining lower-cost energy from an RTO. Moreover, because it bypasses least-cost dispatch, coal self-scheduling can displace low-cost renewable energy within the overall grid mix (Daniel 2018, 2021). Ancillary services are needed to support the reliable operation of the grid and the transmission of energy; they are provided by qualifying generators and demand-side resources. These include such services as regulation (matching generation with very short-term changes in load) and reserves (needed to restore load and generation balance when a supply resource trips off-line). Some ancillary services are neither bought nor sold in the markets and instead are procured directly by the RTO (FERC 2020).

Several RTOs—ISO-NE, the NYISO, and PJM—run mandatory capacity markets, but MISO operates a voluntary capacity market.³ Capacity is the ability of a generator to produce energy or the ability of a customer (or group of customers) to reduce demand. A purchase of capacity provides an option to call on that resource to generate electricity or curtail their consumption (Gramlich and Goggin 2019).

A second critical set of RTO responsibilities includes regional transmission planning, allocating the costs of transmission, and coordinating with neighboring regions to determine opportunities for interregional transmission (FERC 2021a; Figure 2). Planning for and constructing transmission to deliver electricity is essential because generation resources, including solar and other renewables, are often located far from population centers. Although a significant amount of attention has been given to the need for RTO transmission planning improvements, there remains no effective regional planning in the non-RTO regions. For example, the Southeast has limited public participation and a lack of access to basic data, and the Western Interconnection generally only includes incumbent utilities’ transmission plans and does not consider independent developer projects or a more holistic assessment (Howe et al. 2021).

Figure 2 | Core Responsibilities of RTOs

Note: RTO = regional transmission organization.

Source: Authors.

RTO Goals and Mission Statements

The disconnect between the RTO market rules and procedures and the achievement of decarbonization can be seen in the tension between the goals and missions of the RTOs and those of the state governments, local governments, and corporations seeking to achieve bold decarbonization targets by procuring clean energy. The RTOs’ mission statements all incorporate two fundamental goals: ensuring grid reliability and providing competitive markets for electricity, with examples shown in Table 1. One exception is CAISO, which includes the state’s clean energy goals in its mission.

Clean energy advocates note that these RTO goals and mission statements should incorporate the achievement of state clean energy policies (NESCOE 2021; Turner et al. 2021a). The tension between these goals and the expansion of state decarbonization strategies was acknowledged by ISO-NE’s chief executive officer, Gordon van Welie, who recently stated that “efficiency and resource neutrality are prioritized in the wholesale electricity markets while state legislatures are requiring clean energy and decarbonization” (van Welie 2021). Moreover, with the exception of MISO, none of the RTOs includes transmission planning within its primary mission, which is somewhat incompatible with state clean energy goals, given the critical role of transmission in advancing the deployment of renewable energy across the country.

The misalignment of RTO goals and clean energy policies can be seen both in the development of market rules that pose direct impediments to the development of renewable energy (such as the Minimum Offer Price Rule discussed in Section 3) and in the general perception that the RTOs often are reluctant to adapt to newer, cleaner technologies and favor conventional resources (Gramlich 2021; Unel 2020; Welton 2021). Because states retain authority over generation resources, state policies should be fully accommodated by market rules and included in transmission planning. For example, in filing its revised capacity market rules, PJM noted that “state policies supporting certain resources within the PJM Region are a reality to be acknowledged” and such policies “are often designed to address externalities that are not accounted for in PJM’s wholesale markets” (PJM 2021, 7, 8).

Although RTOs can effectively enable the integration of solar and other clean energy resources, improvements are still needed to fully support decarbonization within RTOs. Each RTO has unique characteristics, including the resource mix in its footprint, its geographic size, its governance processes, and the nature of state regulation of the electric utilities within the RTO boundaries. However, there are several common issues within their planning processes and market rules that affect the cost of and access to renewable energy; if addressed, these could unlock the full suite of opportunities they present and accelerate their deployment.⁴

The Intersection of Local Government Goals and Renewable Energy Barriers within RTOs

Many local governments have established ambitious goals for using renewable energy for municipal operations as well as for their community-wide energy consumption. As of February 2022, nearly 200 local governments have established commitments to use 100 percent renewable energy in their communities (Sierra Club n.d.). As local governments implement these goals, it will likely necessitate accessing renewable energy that is sold through an RTO.

The viable renewable energy procurement options for local governments within an RTO depend on several factors, including whether a local government is in a state with a regulated or deregulated electricity market, as well as the state-level policy context and the autonomy provided to substate actors. In deregulated markets or states with enabling legislation, local governments may be able to participate in electricity markets directly (or via an intermediary) through physical power purchase agreements (PPAs) or community choice aggregation. Where options are more limited and local governments must work through a vertically integrated utility, they may be able to procure renewable energy certificates (RECs) from renewable generation within an RTO. Any procurement scenario will be affected by the cost and timeliness related to clean energy siting and interconnection as well as to the value a resource can derive from the wholesale electricity markets.

Therefore, achieving clean energy targets is likely impacted by the evolving rules and policies within RTOs that either support or impede clean energy deployment. Table 2 provides an overview of the barriers within RTOs (with each described in depth in this Section) to expanded renewable deployment and the specific implications that each barrier presents to a local government’s ability to procure renewables. Local governments may be able to mitigate impediments to or amplify opportunities for clean energy by engaging on these issues, as discussed in the companion paper by Ratz et al. (2021).

Growth and Multijurisdictional Constraints

Both within and outside of RTOs, the dramatic growth of renewable resources necessitates a rapid adaptation of rules and procedures to effectively accommodate the changing resource mix and new technologies, including ensuring sufficient flexibility by demand response, storage, and complementary renewables to support the fluctuating output of renewable resources. RTO decision-making and implementation of market rule changes will need to be accelerated, as will the development of coordinated markets and improvements to transmission planning in non-RTO regions.

It would be beneficial to accelerate the planning and construction of transmission in all regions—from the current time frame of 5–10 years—to meet the construction time frame for new renewable resources—about 2–4 years, with shorter time frames for solar (EIA 2021a; Pfeifenberger 2021). One strategy would be to initiate planning for such transmission based on projected renewable procurement prior to the start of resource development.

This time frame is further complicated by the multiple jurisdictions and regulatory entities involved and by the conflicts that have arisen between the federally regulated RTOs and the state and local authorities and legislative bodies, including

• state public utility commissions, which generally regulate distribution utilities (and vertically integrated utilities that operate within some RTOs);
• local regulatory authorities that oversee the public power and rural electric cooperative utilities, which are often not subject to state commission authority;
• state legislatures that implement renewable procurement standards, other clean energy mandates, and policies such as emissions reduction targets and subsidies for clean energy, which determine or influence renewable procurements; and
• local government entities that conduct their own procurement of clean energy.

Moreover, regional and larger-scale interregional transmission projects are subject to federal, state, and local siting and permitting requirements and often require approvals from multiple states.

Transmission

Whereas solar energy has grown significantly on the distribution side, there remains a need for larger utility-scale solar and wind resources. Wind and solar benefit from economies of scale, such that the most cost-effective projects are larger and are located in more remote areas, where there is the potential for large amounts of available land (Caspary et al. 2021). A significant expansion of transmission capacity will be required to fully access renewable resources being developed where the most cost-effective location is geographically distant from load centers (DOE 2021; Gramlich and Caspary 2021; NASEM 2021; NREL 2021; ScottMadden 2020; Unel 2020). Further, because the best locations for wind and solar resources are different from those of retiring coal and nuclear resources, future transmission needs will diverge from those of the past (Gramlich and Caspary 2021). Transmission can also balance the intermittency of renewable resources by integrating a more diverse array of resources from different locations (Gramlich and Caspary 2021; Pfeifenberger 2021; ScottMadden 2020).

Significant investments in transmission will be needed to both connect new renewable energy development to population centers and to obtain the full benefits from RTO dispatches of a wide array of diverse resources. As one example of the potential need to expand the transmission system, Princeton University projects that to achieve economy-wide net-zero carbon emissions by 2050, wind and solar electricity generating capacity would need to increase fourfold—to approximately 600 gigawatts (GW)—and the high-voltage transmission capacity would need to expand by roughly 60 percent to deliver such renewable power to where it is needed (Larson et al. 2020). There are three broad areas where improvements are needed to accelerate the expansion of transmission: transmission planning, interconnection, and cost allocation (Box 3).

Transmission planning

As states and local governments set significant renewable energy targets, the need for an expansion of the grid to meet the growth of renewable resources is greater than ever. As of 2020, there were 680 GW of renewable energy in RTO and most non-RTO utility interconnection queues, equal to 90 percent of all generation. In addition, there were 200 GW of storage, which, when added to the renewable generation, accounted for 92 percent of the total capacity in the queues (Rand et al. 2021).⁵ Interconnection queues comprise projects that have requested interconnection to the transmission system and are undergoing a system impact study to determine what equipment and upgrades are required. Solar energy accounted for 462 GW, or 61 percent, of all active generator capacity in the queue (Rand et al. 2021), nearly eight times the current operational capacity of utility-scale solar, just over 59.5 GW as of December 2021 (EIA 2021b). As discussed below, however, not all of the capacity in the queue will be built.

Ten years ago, in recognition of the need for further improvements in the regional transmission planning process, FERC issued Order No. 1000. This order addressed improvements in transmission planning in both RTO and non-RTO regions, including allowing for greater competition from nonincumbent transmission developers, incorporating public policy requirements into transmission planning, improving cost allocation methodologies, and expanding interregional transmission coordination (FERC 2021a). But many shortcomings remain in the transmission planning processes in both RTO and non-RTO entities, including the following:

• Transmission construction is often focused on rebuilding the current infrastructure rather than planning for future scenarios that incorporate shifts to demand and new technologies. These future scenarios may include considerations around the growth of renewable resources driven by policy requirements and consumer preferences, increased building and transportation electrification, expansions of distributed energy resources (DERs), generator retirements, and alternatives to transmission (FERC 2021a; Gramlich and Caspary 2021; Unel 2020).
• Planning processes tend to be conducted separately for different purposes, such as for reliability, economics, or public policy, rather than a process that holistically incorporates the full range of benefits of transmission (FERC 2021a; Gramlich and Caspary 2021; Pfeifenberger 2021).
• There has been limited development of larger interregional projects that are needed to access the full scope of renewable resources and deliver them to areas of greatest demand. FERC did not create a structured process for coordinating interregional transmission, leading different regions to adopt their own processes and methods for evaluating these projects (Gramlich and Caspary 2021; ScottMadden 2020; Unel 2020).
• Many of the transmission projects built in recent years address local reliability needs or replace facilities at the end of their life, and most of these are exempt from the regional planning process (FERC 2021a; Gramlich and Caspary 2021; Pfeifenberger 2021). Moreover, there is essentially no regional planning in the non-RTO footprint.
• Competition has been extremely limited in the construction of new transmission infrastructure (Unel 2020). Out of more than 800 line-related transmission projects within commission-jurisdictional transmission planning regions that were scheduled to go into service, just 4 were selected as part of a competitive bidding process (FERC 2021i).
• Few projects have been developed to address public policy needs, as specified in Order No. 1000, largely due to the absence of specific criteria or directions from FERC for incorporating public policy into the transmission planning process, along with limited state input into the planning process (FERC 2021a; Gramlich and Caspary 2021; Unel 2020).⁶
• Although Order No. 1000 required that transmission planning provide comparable consideration to “non-wires alternatives,” such as energy efficiency, demand response, and grid-enhancing technologies (including the use of storage as transmission) that improve transmission efficiency, no minimum standards were established by FERC for such alternatives and no cost recovery exists. Therefore, these alternatives have not been adequately considered in the planning processes (DOE 2021; Gramlich and Caspary 2021; Howe et al. 2021; Unel 2020). However, FERC recently issued a final rule requiring the use of one such technology: ambient-adjusted line ratings (FERC 2021b).
• Limited state input on the expected siting constraints for transmission hinders the planning process (Gramlich and Caspary 2021), and inadequate public participation fails to identify and address public concerns about siting (Howe et al. 2021).

These shortcomings in regional and interregional transmission planning have placed additional pressure on the interconnection process. Rather than planning the transmission system comprehensively for future resource development, the interconnection process has limited interaction with transmission planning and addresses resources seeking to interconnect on a case-by-case basis (Caspary et al. 2021; FERC 2021a).

The current interconnection system is characterized by significant delays. Available data on projects in the queue show that just one-quarter of the projects proposed between 2000 and 2015 have been completed, and those rates are lower for renewable resources: 16 percent for solar and 19 percent for wind. Moreover, the median wait time increased from just under 2.0 years for projects built between 2000 and 2009 to about 3.5 years for those built between 2010 and 2020 (Rand et al. 2021). For wind and solar, the median wait times were longer, equal to 3.2 years for projects completed through 2009 and 4.6 for later years (analysis of data from Rand et al. 2021).⁷

Transmission cost allocation

Order No. 1000 established six regional cost allocation principles, including specifying that costs must be allocated to those in the region that benefit from the facilities. Local transmission (the transmission facilities located within a transmission provider’s retail service territory) does not have to be approved at the regional or interregional level unless that transmission provider seeks to have those facilities subject to cost allocation (FERC 2021a).

Allocating the costs of a transmission project enables it to move forward and provides the developer with greater certainty. But the manner in which cost allocation has been implemented for transmission reinforces the shortcomings of transmission planning. Cost allocation can also be difficult and controversial when multiple parties are involved (FERC 2021a; Pfeifenberger 2021). Some observers note that utilities tend to prefer local individual projects that are not included in regional transmission planning and therefore are not subject to cost allocation among multiple parties over broader portfolios of projects. Such local projects are not included in the regional plan and thus avoid being subject to competition (Peskoe 2021; Pfeifenberger 2021). Moreover, cost allocation tends to be performed separately for projects that address specific needs (reliability, economics, or public policy) rather than in a manner that recognizes the multiple values of transmission (FERC 2021a) and, as noted, does not include non-wires alternatives to transmission.

Cost allocation also plays an important role in the withdrawal of projects from the interconnection queue. The procedures and agreements for generation interconnection were established in a very different era than today. FERC Order No. 2003, issued in 2003, standardized these procedures at a time when almost all new interconnecting generators were fired by natural gas (Gramlich and Caspary 2021). Order No. 2003 established a default rule that the costs of upgrades to facilities and equipment between the generation source and the point of interconnection are paid for by the first generator to interconnect, which is known as participant funding. Instead of a holistic process, each interconnection is reviewed independently as the project enters the queue (Gramlich and Caspary 2021).

Under participant funding, the initial entity pays for the needed upgrade and later interconnections are assigned a lower cost. Thus, project developers do not know if they will be assigned these initial higher costs and are incentivized to enter multiple queues and cancel projects with higher interconnection costs (FERC 2021a; Gramlich and Caspary 2021). Because RTOs must study all interconnection requests, this cycle has caused significant delays. Moreover, assigning costs to the first generator does not correctly align the receipt of the benefits of the transmission upgrade with the payment of the costs (Gramlich and Caspary 2021).

Other transmission-related considerations

Another transmission barrier concerns those projects that interconnect to dual-use feeders, which are subject to both state and federal interconnection approval. For example, when a project first interconnects on the distribution system, and then decides to participate in a wholesale market, the feeder becomes subject to FERC jurisdiction. In that case, all subsequent projects on that feeder must use the FERC-regulated interconnection processes rather than state-regulated interconnection process. Because the FERC process is generally more costly, slower, and riskier, developers may drop out under this circumstance. But this issue may potentially be resolved in the implementation of Order No. 2222, which allows DERs to use the state interconnection process (AEE 2021).

Markets

Many observers note that energy, ancillary services, and capacity markets were primarily designed for more conventional fossil fuel and nuclear plants and will require a redesign to incorporate solar and other renewable resources (Cleary and Ratz 2021; Gramlich 2021; Unel 2020; WRI 2020). As explained in Ratz et al. (2021, 7), “While organized wholesale markets are central to providing access to renewable energy and improving integration of clean energy technologies, barriers to clean energy development can arise if the markets do not adapt to changing technologies and goals considering their role managing the grid.”

Resource adequacy and capacity accreditation

All RTOs except ERCOT require load-serving entities (LSEs)⁸ within their footprint to meet a resource adequacy requirement, which is the RTO-determined (with FERC approval) level of capacity needed to meet the projected highest level of demand in a year, plus an additional reserve margin to account for the uncertainty of available generation and load forecasts. In areas outside of the jurisdiction of RTOs, LSEs are still subject to reliability requirements based on a target reserve margin, approved by state commissions or local regulatory authorities.

To determine if the LSE has met its reliability obligation, RTOs measure the capacity value of the LSE’s owned or contracted resources, also referred to as capacity accreditation. Capacity accreditation for conventional resources begins with a determination of the maximum output that is then adjusted downward for historical forced outage rates.⁹ In contrast, renewable resources are measured based on their actual performance during specified hours. A common justification for the different approaches is that solar and other renewable resources are dependent upon the amount of sun and wind and may not necessarily be available when most needed. But there are also similar constraints on the availability of conventional resources during times of system stress that are not captured by the forced outage rates, including limitations on their ability to ramp up quickly, constrained access to fuel or adverse impacts on their operating capability during severe weather events, and the need for maintenance outages. Moreover, units that do not operate may receive too high a capacity value because they do not have forced outages to report (Potomac Economics 2021).

Current approximations of capacity value look at an individual resource’s capacity in isolation and can overstate the reliability of certain resources because they do not capture the negative impacts of correlated outages, such as when constraints on the natural gas supply cause multiple natural gas plant outages or when drought or extreme temperatures impair the capabilities of nuclear plants (ESIG 2021). In PJM, this assumption has caused thermal outage rates to be understated in the capacity valuation methodologies (Baur et al. 2021). With a greater likelihood of more extreme weather events in the future, these correlated outages can be expected to occur more frequently (Rutigliano et al. 2021). Moreover, these approximations of capacity value do not always account for the beneficial correlation of certain resources’ availability with increases in load—as is the case with solar—and demand response, which tend to be at their highest levels during periods of peak demand (McDougall et al. 2021). Further improving the capacity value of renewables—especially solar—is the fact that they are increasingly developed in tandem with storage, creating “hybrid resources” with significantly lower variability than stand-alone renewable resources.

Many RTOs are in the process of reevaluating the methodology for determining capacity values and moving toward adopting a more sophisticated effective load-carrying capability (ELCC) method, which is an assessment of a resource’s contribution to system reliability within the context of the full array of resources and demand (FERC 2021g, 2021h). The ELCC method measures the additional load that a system can supply with a particular generator of interest, with no net change in reliability. It also recognizes the value of the complementary characteristics of a portfolio of resources, such as the diversity benefit of a combined solar-wind-storage fleet (ESIG 2021; Gramlich 2021; McDougall et al. 2021). However, it is not clear if ELCC is the optimal methodology to use.

Capacity markets

Four of the RTOs operate centralized capacity markets, and three of these—ISO-NE, PJM, and parts of the NYISO—oversee mandatory capacity markets. MISO operates a voluntary capacity market, as described in Appendix B. As noted previously, because LSEs are subject to reliability requirements, a capacity market is not necessary to ensure reliability.

In the mandatory capacity markets, LSEs are required to offer all their capacity, including owned or contracted resources, into periodic RTO-run capacity auctions. If that capacity is offered at too high a price, then it will not “clear” the auction and will not be counted toward the LSE’s reliability obligation. In that case, the LSE will have to purchase an equal amount from the auction, paying twice for that capacity (once to build or contract for the resource and a second time to purchase the same amount of capacity from the auction when it does not clear). A rational option, therefore, is that the entity that owns or contracts for a generating resource offers such capacity as a price taker by pricing the offer at zero dollars per megawatt (MW). The entity that owns or contracts the unit is not selling the capacity to another party and is thus indifferent to the auction price.

One set of barriers involves the current rules governing capacity market constructs, which can have far-reaching consequences that affect clean energy resources sold through long-term bilateral contracts. Utility-scale solar and other renewable projects are capital-intensive and use bilateral contracts (such as PPAs) as a guaranteed revenue stream over a long time horizon, which allows the seller to obtain lower-cost financing for the project (Gramlich 2021). Capacity market auction rules and the determination of the capacity value of such resources can create additional complexities for bilateral contracting, depending upon how the contract is structured.¹⁰

States within the mandatory capacity market RTOs have been pursuing decarbonization strategies that entail the procurement of greater amounts of renewable resources and payments to nuclear plants to prevent their retirement. Because such resources are offered into the capacity auction at a zero or low price, as explained above, they lower the clearing price paid to all capacity in the market. Entities whose earnings are more dependent on capacity market revenue, such as merchant natural gas plant owners, have successfully advocated for rule changes to prevent such state actions from lowering the clearing price. These efforts resulted in a significant expansion of the Minimum Offer Price Rule (MOPR) in ISO-NE and PJM, and the analogous buyer-side mitigation (BSM) rule in the NYISO—both significant barriers to renewable energy development (Gramlich and Goggin 2019; Ho 2021; Patton et al. 2021; Rutigliano 2021).

Under the MOPR and BSM, new renewable resources supported by a state, political subdivision, or utility program can be forced to offer into the capacity auctions at a higher price. This raises the risk that the resource will not clear the auction, requiring the LSE to pay twice for the same amount of capacity. Because local governments fall under the political subdivision category, this rule can be interpreted as applicable to their procurement of renewable energy. The companion paper on local government engagement noted that PJM’s MOPR “increased uncertainty over future market rules and delayed capacity auctions have impacted the developers local governments work with,” resulting in projects being “stalled or canceled, threatening their ability to meet their goals and increasing the development costs of projects that do move forward” (Ratz et al. 2021, 10).

These rules, however, are undergoing a significant transition; all three RTOs are in the process of significantly reforming their MOPRs and BSMs as follows:

• FERC approved PJM’s proposal to significantly narrow the applicability of the MOPR to state-sponsored resources, which would be followed by continued stakeholder discussions on further capacity market reforms (PJM 2021). Although the proposal took effect in late September 2021, disagreement among the four FERC commissioners stalled any formal order.
• ISO-NE had stated that it planned to work with stakeholders to develop a proposal to FERC that would eliminate the MOPR in time for the capacity auction to be held in February 2023, which will procure capacity for the June 2026–May 2027 time frame (McCarthy and Gillespie 2021). However, the ISO recently changed course, throwing its support behind a plan to delay the elimination of the MOPR (Mintz 2022).
• The NYISO has proposed exempting clean energy resources from its BSM rules pursuant to New York State’s 2019 Climate Leadership and Community Protection Act. With the exception of some opposition to the NYISO’s “marginal capacity accreditation” framework that was paired with the BSM rule change, this proposal has sweeping, cross-stakeholder support (Howland 2022).

The outcomes of these MOPR and BSM proceedings will be critical for solar energy, especially that which is developed pursuant to state decarbonization laws and policies. Other reforms may also be needed, such as moving away from mandatory capacity markets and implementing voluntary markets to prevent the reinstatement of problematic rule changes in the future (Rutigliano 2021).

Energy and ancillary services markets

Aside from the significant barriers created by the MOPR and BSM, capacity markets generally benefit conventional resources, which have higher operating costs than renewable resources that are generally zero marginal cost resources. Therefore, conventional resources see a greater benefit from participating in a capacity market that provides revenue based on their availability to generate energy rather than the actual production of energy, which is sold separately in the energy market (Bialek et al. 2021; Mays et al. 2019).

Solar and other renewables would benefit from a market design that shifts more revenue to the energy and ancillary services markets and away from the capacity market. But increasing levels of zero marginal cost renewables can also contribute to reductions in energy prices, which, in turn, reduce revenues from that market. The prevalence of bilateral contracting and the sale of RECs offer some protection from these reduced revenues. Yet they do not entirely shield solar from declining prices because energy prices can influence prices paid through bilateral contracts (ERCOT 2021d; Potomac Economics 2021). For example, if the forecasted energy market prices decrease, the buyer would likely lower the price it is willing to pay. The certainty of a long-term contract, however, is beneficial for the seller because it reduces the seller’s risk.

One option for improving prices in the energy and ancillary services markets would be to strengthen scarcity pricing rules, whereby prices are allowed to reach very high levels during times of tight supply. All of the RTOs allow some form of scarcity pricing, and many are seeking to enhance these rules. It is essential that scarcity pricing rules include both demand-side participation and consumer protections, such as limitations on the ceiling or duration of such high prices (known as “circuit breakers”; FERC 2021j). Moreover, wholesale purchasers of energy via bilateral contracts (such as utilities and local governments) are hedged from most scarcity pricing, and retail customers do not see such prices reflected in their bills unless they choose such a rate (Gramlich 2021). Scarcity pricing and other reforms have the potential to shift revenue from capacity to energy and ancillary services markets to the benefit of renewable resources. They also could provide incentives for flexible resources, including storage and demand-side resources, that can help address the intermittency of renewable resources and incentivize buyers to sign long-term contracts to hedge against these prices (Bialek et al. 2021; Gramlich 2021; Hogan and Littell 2020).

In addition to energy and ancillary service pricing reforms, additional ancillary service products may be needed to balance the intermittency of renewable resources, such as for the sale of ramping capability (FERC 2021j). Such products help ensure sufficient flexibility, but many ancillary services can themselves be provided by solar and other renewable resources, leading to additional revenue opportunities (Gramlich 2021; Milligan 2018). Although not discussed in detail here, the ability of solar to provide certain ancillary services is well documented, and expanding access to markets for ancillary services could increase the revenue for solar generation (Kahrl et al. 2021).

Integration of New Resource Types

Hybrid resources

Although a widely agreed upon definition has not been established at FERC and the RTOs, the term hybrid resources may include two or more generating resources that share a single point of interconnection and are either modeled and dispatched as separate resources (also known as colocated resources) or modeled and dispatched as a single integrated resource (FERC 2021e). Hybrid resources have multiple benefits, but their rapid growth presents challenges to the RTOs, which have had little operational experience with hybrid resources (FERC 2021e).

In 2020, hybrid resources that included solar represented 159 GW, or 34 percent, of all solar in interconnection queues, compared to only 6 percent of all wind capacity in queues. The vast majority were solar-plus-storage installations, with small amounts of solar plus wind or natural gas. In 2019, 28 percent of solar and 5 percent of wind projects in the queue were hybrid resources (Rand et al. 2021). One reason for this increasing addition of storage to solar facilities is that under certain configurations, the storage component of the hybrid resources can access federal investment tax credits for solar projects (FERC 2021e; Gensler and Wray 2020).

Developing solar as a hybrid with storage offers multiple benefits in addition to the tax credit. These include an increase in the combined capacity value of the solar hybrid; reduced solar curtailments; improvements in the ability of the solar resource to provide ancillary services; and cost efficiencies through the sharing of the solar and storage permitting, siting, equipment, and interconnection costs (FERC 2021e).

Some of the key measures that can be undertaken by RTOs to maximize the full potential benefits of hybrid resources include, among other steps, revising transmission interconnection rules to ensure that developers do not lose their queue position if a resource is upgraded from a stand-alone solar (or other renewable) resource to a hybrid; updating the market rules and improving the modeling of hybrid resources to allow their full participation in the wholesale markets; and avoiding burdensome metering requirements, such as by recognizing where a hybrid can participate through a single meter (Gensler and Wray 2020).

FERC has recognized both the value to the grid and the challenges of hybrid resources by opening a docket on this topic that has, as of 2021, included a technical conference, the issuance of a white paper, and reports from the RTOs on the status of their efforts to better integrate hybrid resources into the markets. Meanwhile, all RTOs have a process in place to develop market rule changes to better integrate hybrid resources into the markets and transmission interconnection processes (FERC 2021e, n.d.a).

Distributed energy resources

In September 2020, FERC issued Order No. 2222, which requires the RTOs to revise their tariffs to facilitate the participation of DER aggregators in all RTO energy, ancillary services, and capacity markets. DERs are any resources located on the distribution system, any subsystem thereof, or behind a customer meter. DERs include small, flexible resources, such as customer-sited batteries, electric vehicles, rooftop solar, and smart thermostats. Aggregations are typically needed for such resources to participate in the wholesale markets because they tend to be too small to meet the minimum size requirements of those markets.

Under Order No. 2222, the RTOs are required to revise their tariffs to establish DER aggregators as a type of market participant that can register aggregations under one or more participation models that accommodate their physical and operational characteristics. These tariff revisions must establish a minimum size requirement for DER aggregations of no more than 100 kilowatts, and they must address various technical and operational issues, including locational requirements, bidding parameters, metering and telemetry, coordination between relevant parties and authorities, modifications to aggregations, and market participation agreements.

There are two broad categories of benefits for solar energy that will be created by implementing Order No. 2222. First, DERs in wholesale markets provide a new set of flexible resources that will serve to balance the variability of solar. Second, DER participation in the markets will also provide opportunities for new revenue streams for rooftop and community solar projects (AEE 2021).

FERC gave the RTOs a significant amount of flexibility in how they comply with Order No. 2222, and the extent of DER participation in the wholesale markets will partly depend on the details of the RTO tariff revisions. The willingness of distribution utilities to remove impediments to DER participation in the wholesale markets is also crucial for this success (AEE 2021).

As of February 2022, four RTOs had filed their implementation plans with FERC. Only two RTOs filed their compliance plans by the July 2021 due date (CAISO and the NYISO), and four (ISO-NE, MISO, PJM, and the SPP) received deadline extensions. MISO and the SPP will be submitting their filings in April 2022.

There are a number of issues to be addressed in these compliance filings to achieve the full scope of benefits of DER market participation, including the following:

• Fully accrediting these resources for their capacity value in the wholesale market
• Harmonizing DER participation in both retail and wholesale markets while preventing double counting of revenues from each market
• Allowing DERs to update their day-ahead offers prior to the real-time market
• Ensuring that the metering fully captures the performance of DERs but does not impose burdensome and unnecessary telemetry and metering requirements
• Avoiding maximum capacity limits on front-of-meter distribution system resources, such as community solar
• Developing rules and procedures to ensure that resources with state interconnection approvals can participate in the wholesale markets (AEE 2021)

RTO Decision-Making and Stakeholder Processes

Engaging in the stakeholder process is one of the best ways to address RTO rules and procedures that present barriers to solar. But consumer and environmental advocates have expressed concerns about the inability of all stakeholders to have a voice in this process (Donovan et al. 2021a; Ratz et al. 2021). As noted, the companion paper by Ratz et al. (2021) serves as a guide for such participation of local governments at the RTO and FERC levels.

A key impediment to a more equitable stakeholder process is the highly technical and time-intensive nature of decision-making at the RTOs, which benefits entities with greater staff and resources and makes participation more difficult for smaller community, consumer, and environmental groups. These barriers to participation also exist in FERC proceedings, which can be exacerbated by often tight time frames for submitting comments (Box 4). There is evidence that these barriers adversely impact the participation of smaller renewable generation developers. Analyses of the stakeholder processes have found that transmission owners, generation owners with large asset portfolios, and generation owners with a high concentration of natural gas generation are more likely to be active participants in senior-level stakeholder committees (Blumsack et al. 2021), which provide the final feedback to the RTO boards of directors (Parent et al. 2021). Further, this complex and lengthy decision-making process can make it difficult for the RTOs to implement market rule reforms within the time frame that matches the policy and technology developments required for decarbonization.

RTOs vary in the level of participation afforded to nonmarket participants in stakeholder processes, such as local governments, consumer advocates, and environmental groups. Local governments that wish to become members can participate in the RTO end-use sector, along with entities such as industrial customers. Nonprofit environmental organizations can become members in most RTOs, but they are included in the end-use sector in ISO-NE and ERCOT and in the public power sector in NYISO, meaning that the environmental groups may be grouped with entities whose interests differ markedly and where their voting power is diluted. MISO environmental nonprofits have their own voting sector. In PJM, environmental interests are represented by a user group that makes an annual presentation to the board but does not have voting rights (Blumsack et al. 2021). Moreover, states often have a limited say in RTO decisions regarding resource adequacy in regions with mandatory capacity markets (Chen and Murnan 2019).

Public information is limited about RTO decision-making, with significant variation in the transparency of the stakeholder process, including whether various committee and board meetings are open to the public and whether minutes and agendas are made available to the public (Blumsack et al. 2021; Konschnik 2019; Parent et al. 2021).

Wholesale markets present an enabling environment for the integration of clean energy resources into the electricity grid, but barriers still constrain their deployment. Local governments pursuing clean energy and decarbonization goals may be adversely affected by these barriers because they often rely on wholesale markets as part of their procurement strategy. Further, the achievement of community-wide decarbonization will necessitate a grid with a greater share of renewable generation. Therefore, it is critical for local governments to understand wholesale markets and the current barriers to and opportunities for the deployment of additional renewables. By better understanding market rules, transmission policies and practices, and decision-making processes, local governments can prioritize the issues that most significantly affect their goals and craft engagement strategies to address them.

These priority issues will depend on how the local governments plan to achieve their goals and the types of projects they seek to implement, which can range from distributed generation to large-scale PPAs. FERC Order No. 2222 represents a significant near-term opportunity to shape the rules enabling aggregation of distributed generation and other resources. This can be important for local governments, particularly those looking for cost-effective community-wide clean energy solutions. For the deployment of large-scale renewables, transmission expansion, interconnection timelines, and cost allocation are important issues that can influence the time and cost associated with bringing new renewable projects online. The design of energy, ancillary services, and capacity markets (where they exist) may also affect whether a large-scale deal will be financially viable.

Regardless of prioritization or strategy, engagement in wholesale electricity markets is critical to advancing the clean energy goals of local governments and mitigating any barriers related to their priorities. Local governments, either individually or collectively with their peers, have a variety of engagement pathways available to them and can pursue whatever pathway best suits their objectives and desired level of effort. Such engagement should increasingly become an integral part of their decarbonization efforts.

Characteristics

The ISO-NE footprint covers six states: Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont (Figure A1). All six states participate in the Regional Greenhouse Gas Initiative, and Massachusetts sets additional emissions limits for electric generating units through the state’s Global Warming Solutions Act.

Figure A1 | ISO-NE’s Footprint

Source: Sustainable FERC Project n.d.

ISO-NE has a real-time average hourly load of 13.3 GW. The supply mix is dominated by natural gas (42 percent), followed by nuclear (22 percent) and imports (20 percent, which is primarily hydroelectric imports from Canada). In 2020, solar accounted for 2 percent of the supply mix. However, the amount of solar has been increasing rapidly since 2016 (ISO-NE 2021).

ISO-NE conducts forecasts of the total capacity of solar in the region, including behind-the-meter (BTM) resources that do not currently participate in its markets. These forecasts help to improve near-term operability and long-term planning. The most recent forecast shows that the total capacity will grow from just under 4,000 MW as of the end of 2020 to 10,000 MW by the end of 2030, a growth rate of 150 percent. Table A1 shows the growth of each category: solar resources that clear the Forward Capacity Market (FCM) auction and receive a capacity obligation; resources that do not have a capacity obligation and participate only in the energy market; and BTM resources (Black 2021).

Transmission

Many of the broad transmission planning issues identified exist in ISO-NE. Although significant transmission investments have occurred throughout New England, increasing from US$869 million in 2008 to $2.4 billion in 2019, ISO-NE does not conduct transmission planning on a regular schedule to determine the total amount and type of transmission infrastructure needed to expand renewable resources and DERs and study the impacts of electrification (NESCOE 2020a).

The most recent regional transmission plan was issued in November 2021. Although FERC Order No. 1000 established that regional transmission processes must “provide for the consideration of transmission needs driven by public policy requirements,” ISO-NE has never done this (FERC 2011, 1; Marshall 2017). Although almost all states in New England have statutory requirements for greenhouse gas reductions, the New England States Committee on Electricity (NESCOE) stated to the ISO in 2020 that no federal or state public policies were driving transmission needs (Donovan et al. 2021b; NESCOE 2020b).

Transmission planning in ISO-NE uses a siloed approach that evaluates project benefits under a single category of “reliability,” “public policy,” or “economic” rather than a holistic multiple value approach. Although permitted by the ISO-NE tariff, to date, the region has never built a public policy or economic transmission project. Moreover, a number of stakeholders have expressed concern that there is not sufficient consideration of non-wires alternatives and their ability to reduce the need for new transmission (Donovan et al. 2021b).

There are a number of options for funding transmission upgrades within the ISO-NE tariff, including reliability transmission upgrades, the costs of which are shared among the states in proportion to their share of the regional load, and elective transmission upgrades, whereby project developers must pay 100 percent of grid upgrades. A number of stakeholders in ISO-NE have urged the ISO to undertake cost allocation reforms to determine methods that are agreed upon by the states, especially for elective transmission upgrades. Having developers pay the full cost of the upgrades causes many generators to then drop out of the queue (Donovan et al. 2021b). In 2017, ISO-NE adopted an approach that allows, under specific conditions, for two or more interconnection requests to be analyzed as a cluster so that interconnection costs can be allocated to a group of projects rather than sequentially to individual projects. Although the cluster approach may provide some benefits, it does not address the need to holistically plan the transmission system for the future resource mix (Pullaro 2021) or to ensure that the costs are allocated in line with the benefits received (Donovan et al. 2021b).

ISO-NE has pledged to conduct a long-term transmission study of the amount, type, and costs of transmission needed to deliver the study’s projected clean energy and DERs through 2050. This will not include recommendations for specific projects, however, and such projects can only move forward if one or more states elect to develop transmission to meet public policy requirements. ISO-NE has also pledged to incorporate language into its tariff for the continuation of such scenario-based transmission planning (NESCOE 2021).

Capacity Valuation

Clean energy advocates in New England have pointed out that a number of rules reduce the value of solar and other renewable resources for their buyers, for the following reasons (Krich 2021):

• Wind and solar are qualified only based on their actual energy deliveries during times of higher system stress, but traditional resources are credited based on their maximum output capability as demonstrated during a brief seasonal audit and not based on actual delivery.
• The “overlapping impact” test requires new resources to demonstrate that they are incrementally deliverable to the geographic area where the capacity will be used to qualify to submit an offer into the capacity market, but existing resources are running at their full capacity interconnection rights. Because renewable sources are newer to the system, their capacity is sometimes “blocked” by existing fossil-fueled generation.
• Energy-only solar generators that do not participate in the FCM are not counted toward the installed capacity requirement, which is projected to apply to one-third of all solar energy installed in the region in 2030. As a result, these resources neither reduce the installed capacity requirement nor provide low-cost capacity supply, raising the capacity obligation for all LSEs and requiring those who contract with energy-only solar to pay twice to meet their capacity obligation.

ISO-NE has initiated an effort to “identify and implement methodologies that will more appropriately accredit resource contributions to resource adequacy,” and it is “contemplating” a filing at FERC at the end of 2022 (Chadalavada 2021, 5).

Regarding hybrid resources, ISO-NE reports that it does not have specific rules for colocated or hybrid resources, and they can participate in all markets. In 2020, the ISO reported that over 75 colocated facilities either qualified in 2019 or were expected to be qualified in 2020 to participate in the capacity auction, of which 32 requested qualification as single hybrid resources (Wolfson and Boucher 2020). The total capacity of all these resources equaled 220 MW of summer capacity (Wolfson and Boucher 2020), which is less than 1 percent of the total capacity of resources qualified for the capacity auctions held in 2020 and 2021 (Rost 2021).

Hybrid resources are currently not a significant portion of the interconnection queue for ISO-NE (ISO-NE n.d.a.). In 2021, they totaled just 3 percent of queue capacity, and all of these hybrid resources were solar-plus-storage (ISO-NE 2021).

Capacity Market/Minimum Offer Price Rule

ISO-NE has a mandatory capacity market (the FCM) that procures capacity for a 12-month period, 40 months in advance of when that capacity must be available. The 16th Forward Capacity Auction (FCA 16) was held in February 2022 and procured capacity for the June 2025–May 2026 period.

Under ISO-NE’s MOPR, any new resource offering capacity into the auction for the first time must submit an offer equal to or above an offer review trigger price (ORTP) established by ISO-NE. If the resource wishes to submit an offer below the ORTP, it must demonstrate to the Internal Market Monitor (IMM) that such an offer is justified by its costs and anticipated market-based revenues.

For FCAs 11–15, the IMM reviewed nearly 490 requests to offer below the ORTP, and it denied 341 of these new supply offers, which were required to offer into the auction at a higher price than requested by the resource developer. The IMM, however, does not report on these offers by resource type (ISO-NE 2021).

Although the amount of solar that has cleared the FCA has increased from 60 MW to 420 MW between FCA 10 (procuring capacity for the 2020–21 period) and FCA 15 (for the 2024–25 time frame), it is still just 1.2 percent of total resources clearing the auction (ISO-NE 2021). Moreover, only 18 MW of new solar cleared in the 2021 auction, which is 0.7 percent of new resources (Rost 2021).

ISO-NE attempted to accommodate renewable resources being developed pursuant to state policies by implementing a new rule: the Competitive Auctions with Sponsored Policy Resources (CASPR). Under CASPR, implemented in the 2019 FCA, resources that clear the FCA but then decide to retire can purchase capacity from state-sponsored renewable resources that did not clear the auction due to the application of the MOPR. The retiring resources would receive a “severance” payment equal to the difference between their capacity price and the amount paid to the state-sponsored resource. CASPR requires an existing resource exit to make room for a new renewable resource to enter.

CASPR, however, has proved to be ineffective; only one 54 MW portion of an offshore wind project cleared through its substitution auctions in three years. The substitution auctions were not even held in FCA 14 and FCA 15, despite nearly 300 MW and 228 MW, respectively, of state policy resources seeking to enter through those auctions because there were no retiring resources seeking to purchase their capacity (Turner et al. 2021b). A provision of CASPR that provided a means for solar to clear the auction in greater numbers was the Renewable Technology Resource (RTR) exemption from the MOPR. But ISO-NE eliminated the RTR after the most recent FCA, and only a limited amount of the exemption remained in FCA 15 (ISO-NE 2021).

ISO-NE has recently put in place a specific ORTP value for solar to replace the default ORTP of the starting price in the auction, which it did not have previously. Both ISO-NE and the New England Power Pool (NEPOOL) had submitted different proposed ORTPs for solar, and FERC approved ISO-NE’s higher threshold. ISO-NE had been working with stakeholders to develop tariff revisions to remove the MOPR and replace it with very narrow buyer-side market power provisions that would accommodate state and local government renewable procurement, but it recently decided that such changes would not be made until the 2025 auction. In exchange, the ISO will reinstate a 700 MW RTR for the next two capacity auctions.

Decision-Making and Stakeholder Processes

Along with the common concerns about the lengthy and complex stakeholder process, there are several concerns specific to the ISO-NE process, which is conducted by NEPOOL, a private advisory stakeholder body.

NEPOOL decision-making is the least transparent of all the RTOs, and its meetings are not open to the general public or the press (unless the member of the press becomes a member). Only NEPOOL members, NESCOE, and ISO-NE staff may attend. A member of the public may attend only as an invited guest, and although meeting materials are public, all conversations are confidential. ISO-NE board meetings are also closed to the public and press, and only members of the board and ISO-NE management may attend (Parent et al. 2021).

Along with large energy users, environmental groups and consumer advocates are included as NEPOOL members in the end-use sector. The sector’s vote in the NEPOOL Participants Committee is weighted by one-sixth, which dilutes the votes of these public interest entities (Donovan et al. 2021a). (All six sectors each have equal voting weight.) The Participants Committee is the senior committee that serves as the primary avenue for input to the ISO-NE board (Parent et al. 2021).

Although states are generally represented by the state commissions in the RTOs, there are two state entities that participate in ISO-NE stakeholder processes: NESCOE, which represents the interests of the New England governors, and the New England Conference of Public Utility Commissioners (NECPUC), representing the state commissions. NESCOE focuses primarily on resource adequacy and transmission planning. NECPUC addresses a range of wholesale market issues that are of interest to the state commissions and also participates in the board of director nominating process (Chen and Murnan 2019). Yet these entities have a limited voice in decisions, with the only formal role for the states being NESCOE’s ability to vote on the determination of the reserve margin (Donovan et al. 2021a). NESCOE is, however, allowed to make proposals in the NEPOOL technical committee meetings; propose alternative cost allocation provisions to those proposed by transmission owners, which must be included in the filing to FERC; and identify how some of the costs of public policy transmission projects are allocated (Parent et al. 2021).

Meetings of the ISO-NE Planning Advisory Committee, which provides input to the ISO on transmission planning, are open to the public, but no voting occurs in this committee (Parent et al. 2021). The committee will provide a forum for the discussion of ISO-NE’s 2050 transmission study.

In October 2020, NESCOE took steps outside of the formal stakeholder process to address shortcomings in the ISO rules and policies, with the release of a statement “for a clean, affordable, and reliable 21st century regional electric grid,” which identified needed reforms to wholesale electricity market design, transmission, and governance (NESCOE 2021). Following the release of this statement, the New England states held a series of forums that addressed wholesale market design, transmission planning, governance, and equity and environmental justice; these forums were followed by a June 2021 report from NESCOE providing its recommendations (NESCOE 2021). The forums established a foundation for future engagement by establishing the needed areas of reform.

Order No. 2222

With the growth of solar energy in New England, implementing Order No. 2222 is important for wholesale market participation of BTM and community solar as well as demand response and other responsive DERs, such as electric vehicles, which can balance the intermittency of that solar.

ISO-NE submitted its compliance filing with Order No. 2222 on February 2, 2022. Stakeholders supporting DERs had advocated for tariff changes that would allow all types of DERs to participate in the wholesale markets and reduce burdens to such participation (Dwyer 2021). Environmental groups, as well as a number of demand-response, energy efficiency, and renewable energy companies, abstained or objected to ISO-NE’s final proposal in the stakeholder process.

Characteristics

The MISO footprint covers 15 states, including all or most of Arkansas, Illinois, Indiana, Iowa, Louisiana, Michigan, Minnesota, and Wisconsin. Renewable energy, and especially solar, is expected to grow dramatically in MISO. As 2021, solar was the largest category of active projects in MISO’s interconnection queue, representing 61 percent of the capacity in the queue, with an additional 11 percent comprising hybrid resources, all of which included solar. Wind represented another 12 percent, and standalone storage equaled 10 percent (MISO 2021a). However, a significant portion of these projects will not be completed, as noted previously.

Figure B1 | MISO’s Footprint

Note: ISO = independent system operator.

Source: Sustainable FERC Project n.d.

Transmission Planning

Transmission will be essential to connecting additional renewable energy to load in the region. MISO’s analyses show that renewable energy could reach 30 percent of the energy mix in the region by 2026, and that a 40 percent renewables scenario will require a “massive deployment of transmission solutions” (Prabhakar et al. 2021, 51). As with many areas, renewable energy growth in MISO is not expected to occur uniformly on a geographic basis, with some areas expected to be close to 100 percent renewable when the region reaches 30 percent. MISO also found that having adequate transmission enables access to diverse, variable resources across the footprint. Because transmission also increases the interchange of resources with neighboring RTOs, this will likely better utilize the available and diverse resources across the entire Eastern Interconnection. These findings greatly underscore the need for sufficient transmission capacity (Prabhakar et al. 2021).

Compared to other RTOs, MISO’s transmission planning presents several opportunities for solar. One positive development was the use of a Multi-Value Project (MVP) approach to evaluate a portfolio of transmission projects in a more holistic manner that accounts for multiple benefits. Seventeen MVPs were approved in 2011 that were found to provide public policy, reliability, and economic benefits in the MISO footprint (which did not include MISO South at that time), all of which had been completed as of July 2021 (MISO 2021d). MISO has not replicated this MVP approach to planning since 2011, and transmission-related barriers to solar still exist within the ISO. Most transmission projects focus on the local reliability of the incumbent utility (Gramlich and Caspary 2021). In both the 2020 and 2021 MISO Transmission Expansion Planning (MTEP), the majority of the planned transmission expense is for “other projects,” most of which address local, rather than regional, needs—either to replace aging infrastructure or meet local reliability needs.¹¹ Such projects accounted for 67 percent of the total transmission expense in the 2020 MTEP and 83 percent in 2021. No projects were proposed in the 2020 or 2021 MTEPs to support public policy needs.

The environmental sector in MISO has also pointed out that the 2021 draft MTEP contains overly conservative projections for future levels of renewable resources and does not reflect more recent changes in utility plans for the retirement of coal plants and increased construction of renewables (Azar 2021).

Another shortcoming in the MTEP process is that, as MISO acknowledges, non-transmission alternatives are not considered on a level playing field with transmission. One issue is that new generation or storage cannot be considered as an alternative to transmission unless it has a signed interconnection agreement; however, projects in the interconnection queue face significant delays, and other requirements for being selected as an alternative are not clearly specified (MISO 2022a). Moreover, several stakeholders have noted that MISO does not correctly model the dispatch of storage when determining its potential to alleviate transmission constraints and reduce the need for transmission (Peters 2021a). MISO does allow for a storage facility to be considered as a transmission-only asset in the transmission plan without an interconnection agreement. But a storage as transmission-only asset is restricted to transmission and cannot participate in the energy or ancillary services market (other than to receive or inject energy as needed to perform as transmission; MISO 2022b).

Interconnection

Clean energy supporters have expressed concern that MISO will not have sufficient transmission capacity to accommodate the growth of renewables in the region, and that the high interconnection costs for new resources, typically paid by the initial interconnecting resource, are causing renewable resources to rapidly drop out of the queue (Payne 2021). For example, an analysis by Grid Strategies found that between January 2016 and July 2020, 245 clean energy projects in advanced stages of the MISO generator interconnection process chose to withdraw from the queue. Grid Strategies reports that interviews with the owners of these projects indicate that network upgrade costs were the primary reason for withdrawing (Gramlich and Caspary 2021). A recent analysis of 12 potential network upgrades in MISO and the SPP by ICF Resources showed that 10 of these projects had positive benefits for the region, as measured by generation cost savings, and would also enable more renewable generation and reduce fossil fuel output (Sankaran et al. 2021).

In addition to these high costs, projects on the interconnection queue face a long wait, with MISO processing times estimated to last around three years (Gramlich and Caspary 2021).

One way to reduce the interconnection costs is to allow for the use of additional storage. This would mitigate transmission constraints and would not require additional transmission upgrades; however, MISO is not incorporating this option into the interconnection process (Peters 2021b).

Long-Term Planning

MISO has initiated a suite of efforts to address what it terms the Reliability Imperative. This is described as the “significant challenges” created by the growth of renewable resources, DERs, and demand response as well as more frequent extreme weather events (MISO 2021b, 23). These efforts include both changes to the markets and transmission planning.

As part of the Reliability Imperative, MISO has initiated a Long-Range Transmission Planning (LRTP) process that has been widely praised by multiple renewable energy supporters (Gignac and Gomberg 2021; Kowalczyk 2021; McIntire 2021; Payne 2021). LRTP involves planning for future transmission needs by modeling a range of different future scenarios and considering multiple drivers of the need for transmission, which will allow MISO to develop a transmission infrastructure framework for the influx of renewable resources and to maintain system reliability. The MISO stakeholder process continues to discuss which methodology should be used to allocate the costs of the LRTP projects.

Interregional Transmission Planning

MISO reports that on an annual basis, it works with the SPP and PJM to identify issues on the seams, perform studies, and jointly evaluate interregional transmission solutions that may be more efficient or effective than a regional solution (MISO 2021c).

In 2018, MISO’s Organization of MISO States (OMS) and the SPP’s Regional States Committee formed a liaison committee to identify issues and potential solutions to enhance the benefits from better coordinated seams policies (SPP 2018). MISO and the SPP then announced in 2020 that they would collaborate on a study designed to identify interregional transmission projects with comprehensive, cost-effective, and efficient upgrades (SPP 2020). MISO and PJM also announced in August 2021 that they would not initiate a coordinated study, noting that no interregional constraints or drivers were identified that would warrant such a study (Goldberg 2021). The Environmental Sector has urged MISO to engage in continued joint transmission planning with its neighbors, noting that doing so is essential to both ensuring reliability during extreme weather events and in a high renewable future (Azar 2021).

Capacity Markets and Accreditation

MISO operates a voluntary capacity market without a MOPR, which avoids a primary barrier that exists in ISO-NE, PJM, and the NYISO. Its resource adequacy measures are important, however, because they influence how the LSEs conduct their resource planning to comply with their reliability obligations (MISO 2020).

Because of the dramatic changes in its resource portfolio and increases in extreme weather events, MISO implemented the Resource Adequacy and Need initiative to revise its approach to resource adequacy. In November 2021, MISO filed a proposal with FERC outlining several changes to its resource adequacy methodology, including a seasonal standard, rather than only planning for summer peak load, and revised accreditation methods intended to measure the actual performance of resources at times of system stress (Kessler 2021). For thermal resources, this has involved a complex methodology to determine those hours when there is the greatest risk. Solar and wind accreditation would continue to use their current methodologies, with solar based on historical performance during specific hours of the day during each season and wind using a seasonal ELCC method (MISO 2021f).

The environmental sector in MISO expressed multiple concerns about the methodology being used for these resource adequacy changes during the stakeholder process, including that MISO may be including hours in the accreditation that do not represent a system risk, that the determination of a seasonal planning reserve margin may not be accurate, and generally whether MISO had conducted a sufficient analysis for a submittal to FERC (O’Connell et al. 2022). A majority of stakeholders voted in support of a motion asking MISO to delay the proposal until a number of concerns were addressed and a more robust analysis is performed, but MISO decided to file the proposal as planned (MISO 2021e).

MISO reports that requests to integrate hybrid resources are increasing. Although it has no operational experience with hybrid resources and no defined mechanism for their participation in the markets, it has submitted a proposal to FERC establishing a definition of a hybrid resource and a methodology for accrediting capacity from these resources (Blackwell 2021). The proposal was supported by the solar industry as a positive step in allowing hybrid resources to participate in MISO’s capacity market (Gallagher et al. 2021). MISO is, however, continuing to discuss hybrid resource market participation with stakeholders and may need to further refine its tariffs as hybrid resources begin operation and more data is available (Gallagher et al. 2021).

Energy and Ancillary Services Markets

Meanwhile, MISO has delayed the bulk of its effort to reform its scarcity pricing and consider new ancillary products. Ideally, energy and ancillary services reforms should be conducted in tandem with resource adequacy reforms because they are both aimed at ensuring that resources are available to respond when needed and are sufficiently flexible to respond to the variability of renewable resources.

Order No. 2222

As of June 2021, MISO had an estimated 7.2 GW of DERs, of which 31 percent were solar. Over 60 percent of the DER capacity is registered with MISO, almost all of which is demand response. Solar and demand response are the primary types of nonregistered residential DERs, and the nonregistered nonresidential DERs represent a greater variety of resources (OMS 2021).

Maximizing the participation of DERs will benefit solar directly and will also allow for more resources, such as demand response, which can balance the intermittency of solar. MISO is currently engaged with stakeholders to develop its compliance filing on Order No. 2222, to be filed in April 2022. Multiple stakeholders supporting DER integration have made suggestions to ease DER participation and avoid burdensome requirements, such as by allowing the submission of aggregated metered data, making the determination of whether there is double counting of wholesale and retail revenues at the DER registration process and not in each transaction, and avoiding costly telemetry requirements (Vickers 2021). Regardless of how well the MISO rules are designed, the distribution utilities will also play a critical role in facilitating DER participation in the wholesale markets.

Decision-Making and Stakeholder Processes

Several features of MISO’s governance structure provide greater opportunities for improvements in market rules and transmission planning.

Nonmember voting rights

The Environmental and Public Consumer Advocate Sectors each have two representatives, equal to an 8 percent voting share, in the Advisory Committee, and the State Regulatory Authority Sector has a 16 percent share. The Advisory Committee serves as a forum for stakeholders to provide input and recommendations to the MISO board. In the Planning Advisory Committee, which provides input to MISO staff on the transmission plan, each sector has an equal 10 percent weighted vote (Parent et al. 2021). These votes, however, are advisory, and MISO management and the board are not required to follow them. In other committees, such as the Resource Adequacy Subcommittee, each stakeholder (whether a member or not) has one vote, with such votes also considered advisory, as demonstrated by MISO’s decision not to delay the recent resource adequacy proposal as requested by a majority of subcommittee participants (Doshi 2021).

Transparent stakeholder processes

All meetings of the MISO board and committees are open to the public, except when the board is in executive session. Interested members of the public, including MISO stakeholders, can provide oral and written comments during the open portion of the board meeting.

Although the OMS, an independent organization representing the state regulatory authorities, does not have a role in selecting or removing MISO board members, representatives from the State Regulatory Authority and Public Consumer Advocate Sectors are eligible to serve on MISO’s board nominating committee.

A structured role for the Organization of MISO States

The OMS has a defined role in the transmission planning process, as described in detail in Attachment FF of the MISO tariff (MISO 2022b). The OMS can suggest modifications to MISO’s planning principles and objectives or to the scope of the regional plan; provide modeling inputs or assumptions and cost-benefit analyses for certain projects; express concerns that arise during the regional planning process; submit a reconsideration request for non-generation interconnection projects meeting certain criteria; and, at the end of the process, provide an assessment of the planning process to which MISO is obligated to respond (Parent et al. 2021). For example, the OMS provided feedback on the MTEP that included the importance of supporting local, state, and federal policy preferences (OMS 2021).

Moreover, the OMS can request, under certain circumstances, that MISO file an alternative transmission cost allocation approach under Section 205 of the Federal Power Act when MISO is planning to file a new or modified cost allocation proposal. Filing a proposal under Section 205 only requires a demonstration that the proposed change is just and reasonable. Without the ability to request a Section 205 filing, the alternative would be to file a complaint under Section 206, which requires a demonstration that the existing rule is not just and reasonable, a more difficult burden of proof (Chen and Murnan 2019).

Characteristics

ERCOT covers about 90 percent of the electric load in Texas (Figure C1). The transmission of electricity in ERCOT is not subject to FERC jurisdiction because its transmission system is located entirely within the state of Texas, although it is subject to FERC jurisdiction for questions of reliability. Instead, the Public Utility Commission of Texas (PUCT) has jurisdiction over ERCOT, and PUCT approval is required for all ERCOT rule changes. As a result, FERC initiatives that can provide additional opportunities for solar, such as Order No. 2222, do not apply to ERCOT.

Figure C1 | ERCOT’s Footprint

Source: ERCOT 2021c.

Texas implemented retail choice and restructured the investor-owned utilities in 2002, but public power and cooperative utilities continue to operate as vertically integrated utilities that own or purchase power to serve their retail customers.

Significant amounts of renewable energy, especially wind power, have been developed in Texas, which, as of 2020, ranked highest among the states for total renewable power installations (ACP 2021) and second for solar (SEIA 2021b). Total solar capacity in ERCOT reached 6 GW by the third quarter of 2021, and wind totaled 27.5 GW (ERCOT 2021d). Solar development is likely to continue to accelerate; it represents over 53 percent of the MW in the ERCOT interconnection queue as of February 2022 (ERCOT 2022).

Renewable power development in Texas is not driven by a state requirement. Although the Texas legislature established a Renewable Portfolio Standard in 1999 and increased it in 2005, the state surpassed the standard’s goal of 10,000 MW of renewable energy by 2025 in 2009 (NC Clean Energy Technology Center n.d.). Renewable development since that time has continued to expand because of actions taken by corporations, public power and cooperative utilities, and independent generation owners.

Winter 2021 Outages and Subsequent Actions

Changes to ERCOT market rules are likely to result from the response of the state legislature and the PUCT to the power outages that occurred during the second week of February 2021, when Texas experienced a period of extreme cold temperatures and millions of customers lost power. At the highest level of outages, over 26 GW of thermal generation were on forced outages, and wind generated about 3 GW below what was expected (King et al. 2021). Solar outages were generally below 1 GW (ERCOT 2021e).

These events spurred several pieces of legislation in the state, most notably Senate Bills 2 and 3. The former makes a number of changes to the ERCOT board and requires the PUCT to exercise oversight more frequently and thoroughly. The latter includes requirements aimed at preparing for, preventing, and responding to weather emergencies and power outages, including creating requirements for the weatherization of generation and transmission facilities. It also required the PUCT to modify the design, procurement, and cost allocation of ancillary services for the ERCOT region in a manner consistent with cost-causation principles and on a nondiscriminatory basis (Texas Legislature Online 2021).

After signing these two bills, Governor Greg Abbott asked the PUCT to take a number of actions, including the following, which favor conventional resources over renewable energy (Office of the Texas Governor 2021):

• Redesigning the market to create incentives that “foster the development and maintenance of adequate and reliable sources of power, like natural gas, coal and nuclear power.”
• “Allocate reliability costs to generation resources that cannot guarantee their own availability, such as wind or solar power.”
• Accelerating the development of transmission to connect “dispatchable generation,” which the governor defines as “natural gas, coal, and nuclear power plants.”

The PUCT has since opened several dockets and filed orders pertaining to weatherization and market design, with the latter addressing the governor’s cost allocation proposal, among other items. Several stakeholders filing in the PUCT market redesign docket opposed the assignment of ancillary services costs to renewable energy, with some pointing out that renewable energy providers can self-provide or hedge these services (Jewell 2021) and that many solar developers already have a requirement for the provision of replacement power built into their contracts (Hemmeline 2021). Moreover, there is no evidence that ancillary services costs result from renewable energy (Hemmeline 2021; Stoff 2021), and the allocation of these costs could deter future renewable energy development (Stoff 2021).

On December 16, 2021, the PUCT approved some initial changes to the energy market, including steps to avoid extreme price spikes and to implement new ancillary services, but without assigning those costs to renewables. The PUCT is also pursuing a second phase of actions, including the development of “a load-side reliability mechanism that will serve the purpose of ensuring the supply of dispatchable generation is sufficient to meet system demand” (Haguewood 2021, 4). The creation of such a mechanism for capacity payments has caused some concerns among stakeholders, including renewable energy supporters, that it creates additional costs and discriminates against solar and other resources (SEIA and TSPA 2021).

Transmission

Aside from the potential for the PUCT to create new barriers through the allocation of ancillary services costs, a key to continuing the growth of solar and other renewables in ERCOT is having sufficient transmission.

Transmission within Texas was expanded following the state legislature’s passage of a bill in 2005 requiring the PUCT to designate Competitive Renewable Energy Zones (CREZs), which were areas with high levels of planned wind development and where new transmission would be constructed. The CREZ transmission was completed in 2014 and designed to serve 18.5 GW of wind capacity. Yet because transmission cannot be restricted to a single resource type, the CREZ lines benefit multiple resources within the state (Lasher 2014).

But with greater levels of renewables, more transmission will be needed. To alleviate existing transmission constraints, the PUCT recently approved additional transmission in the Rio Grande Valley (PUCT 2021). ERCOT issues an annual regional transmission plan, produced with stakeholder input, that identifies transmission investments needed to address reliability and economic needs over a six-year horizon. As part of this plan, ERCOT conducts several sensitivity analyses to determine transmission needs under alternative assumptions, including a high renewable penetration scenario (ERCOT 2020c).

ERCOT is also required under state statute to conduct LRTP over both 10- and 15-year planning horizons under multiple scenarios and to report the results to the legislature every other year. The LRTP also serves as a guide to the annual transmission plan. The most recent LRTP included the following findings (ERCOT 2020b):

• Significant renewable energy growth was included in all scenarios because the projected capital cost of wind and solar generation is expected to be recovered by energy prices.
• Since wind and solar resources have different diurnal generation patterns, they complement each other.
• Transmission limitations could reduce the construction of wind and solar generation and could also shift new wind and solar development away from more resource-rich regions to sites closer to major urban demand centers, which, in turn, could reduce the amount of demand that can be served by renewable resources.

Capacity

Although renewable energy supporters are seeking to ensure that any market changes that emerge from the PUCT proceedings described above do not disadvantage renewables, there are currently no MOPR or capacity valuation concerns because ERCOT does not have a capacity market or a reserve margin requirement. Instead, ERCOT uses a scarcity pricing mechanism that causes energy prices to rise when operating reserves fall below a certain level,¹² reaching as high as $9,000 per megawatt hour, much greater than levels at other RTOs/ISOs. The theory behind scarcity pricing is that if capacity reserve margins are low, energy prices will spike to high levels and attract investment in new resources, which will continue until increases in capacity lead to lower prices (ERCOT 2020a).

The events of February 2021 showed that there are some limitations to this approach. Prices spiked to extreme levels while customers experienced widespread power outages, and about half of the generation capacity was unavailable. The PUCT approved in late 2021 a reduction of the price cap to $5,000 per megawatt hour.

Decision-Making and Stakeholder Processes

ERCOT’s governance process is transparent and allows for the public to comment on proposals. However, there is not a separate voting sector for environmental interests. The primary committee for decision-making is the Technical Advisory Committee, which makes policy recommendations to the Board of Directors (ERCOT n.d.).

The Technical Advisory Committee comprises representatives from retail providers, generation owners, power marketers, utilities, and consumers (ERCOT 2021b). Each sector has four representatives, each of whom has one vote; the exception is the Consumer Sector, which has six representatives (two representatives for residential, consumer, and industrial consumers; ERCOT 2021a).

BSMbuyer-side mitigation

BTMbehind-the-meter

CAISOCalifornia Independent System Operator

CASPRCompetitive Auctions with Sponsored Policy Resources

CREZCompetitive Renewable Energy Zone

DERdistributed energy resource

ELCCeffective load-carrying capability

ERCOTElectric Reliability Council of Texas

FCAForward Capacity Auction

FCMForward Capacity Market

FERCFederal Energy Regulatory Commission

IMMInternal Market Monitor / Independent Market Monitor

IPPindependent power producer

ISOindependent system operator

ISO-NEIndependent System Operator New England

LRTPLong-Range Transmission Planning

LSEload-serving entity

MISOMidcontinent Independent System Operator

MOPRMinimum Offer Price Rule

MTEPMISO Transmission Expansion Planning

MVPMulti-Value Project

NECPUCNew England Conference of Public 
 Utility Commissioners

NEPOOLNew England Power Pool

NESCONew England States Committee on Electricity

NYISONew York Independent System Operator

OMSOrganization of MISO States

OPPOffice of Public Participation

ORTPoffer review trigger price

PJMCCCPJM Cities and Communities Coalition

PPApower purchase agreement

PUCTPublic Utility Commission of Texas

RECrenewable energy certificate

RTOregional transmission organization

RTRRenewable Technology Resource

SPPSouthwest Power Pool

vPPAvirtual power purchase agreement

ancillary services market: A wholesale market for resources that can come online quickly and balance the system as it moves electricity. Ancillary services vary by market but typically include reserves and regulation products.

bilateral contracts: A contract in which a mutual agreement has been made between the parties (e.g., buyers and sellers of electricity).

capacity: The total amount of electricity that a resource is able to generate when needed.

capacity accreditation: The capacity value of a resource, as measured by the RTO.

capacity market: An auction run by an RTO where generators sell their availability to operate when needed.

clearing price: The price of the last generation resource bid into an auction that brings energy supply to match demand. All resources bidding into the auction at a lower price will receive this “clearing price.”

day-ahead market: Forward energy market to buy and sell electricity to the next day. Hourly locational marginal prices are calculated for the next day, based on supply, demand, and scheduled transactions between buyers and sellers of energy.

dual-use feeders: A transmission line on the distribution system that becomes subject to FERC jurisdiction due to an interconnected project’s participation in wholesale markets.

effective load-carrying capability: A measure of the additional load that the system can supply with a particular generator of interest, with no net change in reliability. Some RTOs use this measure to determine the capacity value of certain resources, generally renewable resources and storage.

energy market: An auction in which electric suppliers offer to sell the electricity generated for a particular bid price, and LSEs (the demand side) bid for that electricity in order to meet their customers’ energy demand on a day-to-day basis. Supply-side quantities and bids are ordered in ascending order of offer price. The market “clears” when supply meets demand, and generators receive this market price per megawatt hour of power generated.

grid-enhancing technologies: Hardware or software that increases the capacity, efficiency, and/or reliability of the transmission grid, providing grid-wide benefits.

independent market monitor: An organization or individual retained by an RTO to detect attempts to exercise market power and fraudulent behavior, evaluate market performance, identify market design imperfections, and monitor market activities and transactions.

independent power producer: Nonutility generators that generate electricity for sale into the electricity network and can typically sell power to a single third-party customer via a PPA.

independent system operator: Independent, membership-based, not-for-profit organization that ensures reliability and optimizes supply and demand bids for wholesale electric power. Areas within an ISO are considered to be organized wholesale markets.

interconnection: Processes of connecting new generation to the transmission system, guided by RTO rules and processes where organized wholesale markets exist.

interconnection queue: A list of transmission and generation projects that are currently proposed and seeking to join the grid.

load-serving entity: An entity that has contractual or regulatory obligations to connect its load to the transmission grid

mandatory capacity market: A capacity market in which all capacity used to meet required reserve margins must be purchased through a capacity market auction operated by the RTOs, including capacity that is self-supplied.

Minimum Offer Price Rule: A rule by which new resources supported by a state, political subdivision, or utility program can be forced to offer into the capacity auctions at a higher price than they choose.

Order No. 1000: A final rule, completed in 2015, that reforms FERC’s electric transmission planning and cost allocation requirements for public utility transmission providers.

organized wholesale market: The purchase and sale of electricity from generators to resellers, along with the ancillary services needed to maintain reliability and power quality at the transmission level. Resellers include electricity utility companies, competitive power providers, and electricity marketers.

participant funding: The default rule, established by Order 2003, that the costs of upgrades to facilities and equipment between the generation source and the point of interconnection are paid for by the first generator to interconnect.

price taker: An electricity generator that bids into the hourly market at zero and is indifferent to the price.

real-time market: A spot market in which electricity is procured for immediate delivery based on locational marginal prices that are calculated at five-minute intervals.

reserve margin: Excess capacity retained above the amount needed to meet expected peak demand to ensure reliability.

reserves: Generation resources that can quickly come online within 10–30 minutes in the event of an unexpected loss in generation, such as a downed generator.

regional transmission organization: Independent, membership-based, not-for-profit organization that ensures reliability and optimizes supply and demand bids for wholesale electric power. Areas within an RTO are considered to be organized wholesale markets.

self-scheduling: The practice of automatically dispatching a resource without it being required to offer below the clearing price. This practice is frequently used by coal-fired generation, and it depresses the percentage of clean energy within the overall grid mix.

voluntary capacity market: A market that allows LSEs to choose whether or not to purchase from the capacity market.

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1. 1Unless referring to a specific ISO or RTO, the authors henceforth use the term RTO to reflect both types of operators.
2. 2There are two nascent markets—the CAISO Energy Imbalance Market and the SPP Western Energy Imbalance Services—that operate only a real-time market.
3. 3Capacity markets in ISO-NE, the NYISO, and PJM are not specifically defined as mandatory, but the impact of market rules leads to a mandatory capacity market. For the purposes of this paper, we refer to these capacity markets as mandatory even though that language is not used within the markets.
4. 4For the non-RTO regions, a foundational step for better integrating renewables is to establish an RTO-operated wholesale market and a regional planning process that incorporates the recommendations within this paper. Cost savings and improved renewable integration can also be obtained from interim markets, such as the energy imbalance markets operated by CAISO and the SPP (Chen 2020; CPUC 2021).
5. 5Based on data from all RTOs and 35 utilities, representing about 85 percent of the U.S. electric load.
6. 6One exception is the SPP, which gives the Regional States Committee the right to approve certain proposals regarding the transmission planning process (SPP 2021).
7. 7These data are only available for a subset of projects and only from four RTOs: CAISO, ISO-NE, the NYISO, and PJM.
8. 8An LSE serves electricity users within a control area and has been granted the authority or has an obligation to sell electric energy to end users located within that area. These entities are power marketers and aggregators. See the FERC Glossary (https://ferc.gov/industries-data/market-assessments/overview/glossary)/span>).).
9. 9A forced outage is an unplanned outage and does not include planned or maintenance outages.
10. 10If the purchaser is a utility and the contract includes the purchase of capacity, and the capacity market rules or the accreditation methodology lower the amount of capacity that clears the auction, then the value of that purchased capacity is reduced. In some contracts, such as the Massachusetts utilities’ offshore wind contracts, the purchase of capacity is not included in the contract and it is up to the seller to decide whether to participate in the capacity market (Massachusetts DER 2021). In that case, the seller may need a greater contracted energy price to compensate for any lower-than-expected revenue from sales into the capacity market.
11. 11These local reliability projects are not included as a baseline reliability project because they do not address North American Electric Reliability Corporation or regional reliability requirements.
12. 12Operating reserves refers to the amount of generation set aside in the event of an emergency rather than generating electricity.

We are pleased to acknowledge our institutional strategic partners that provide core funding to WRI: the Netherlands Ministry of Foreign Affairs, Royal Danish Ministry of Foreign Affairs, and Swedish International Development Cooperation Agency.

Although the content of this paper is the sole responsibility of the authors, we would like to thank the following individuals for their thoughtful insights, comments, and reviews. We thank the expert interviewees who provided guidance on key issues within wholesale electricity markets, including Melissa Alfano, Kevin Lucas, and Gizelle Wray from the Solar Energy Industries Association; Liz Delaney from Borrego Solar; Doug Hurley from Synapse Energy Economics; Daniel Hall from the American Clean Power Association; Justin Vickers from the Environmental Law and Policy Center; Dr. Joshua Rhodes from the University of Texas at Austin; and Caitlin Smith from Jupiter Power LLC (formerly AB Power Advisors).

We also thank members of our expert advisory committee who conducted a review of an early draft of this paper, including Ann McCabe from the Regulatory Assistance Project; Ellen Katz from the City of Cambridge, Massachusetts; Heidi Bishop Ratz from the Clean Energy Buyers Alliance; Jeff Dennis from Advanced Energy Economy; and Jennifer Chen of ReGrid and WRI.

This report was made possible thanks to the support of the U.S. Department of Energy through the Office of Energy Efficiency and Renewable Energy under the Solar Energy Technologies Office Award Number DE-EE0009003. This report was prepared as an account of work sponsored by an agency of the U.S. government. Neither the U.S. government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the U.S. government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the U.S. government or any agency thereof.

The authors thank the following individuals for their insightful comments and critical reviews: Alex Dane, Karl Hausker, and Michelle Levinson of WRI; Thomas Bartholomew of the D.C. Department of Energy and Environment; Maggie Kristian and Matt Prorok of the Great Plains Institute; Justin Vickers of the Environmental Law and Policy Center; Doug Hurley of Synapse Energy Economics; and Doug Lewin of Stoic Energy.

The authors also thank Laura Malaguzzi Valeri and Emily Matthews of WRI’s Research, Data, and Innovation office for their insights; Lauri Scherer for copyediting; and Shannon Collins for design.

Elise Caplan recently joined the American Council on Renewable Energy (ACORE) as the Director of Electricity Policy, where she will monitor and respond to regulatory developments impacting the U.S. renewable energy industry at FERC, RTO/ISOs, state utility commissions, federal agencies, and other entities as appropriate. Prior to joining ACORE, she was an independent consultant with expertise in the wholesale electricity markets. Her two primary clients were the Natural Resources Defense Council’s Sustainable FERC Project and WRI. For the former, Ms. Caplan supported the council’s advocacy for wholesale market design, transmission policy, and public participation to foster the growth of clean energy. Until the end of 2020, Ms. Caplan was the Director of Electric Markets Analysis for the American Public Power Association, the trade association representing the nation’s public power utilities.

Contact: caplan@acore.org

Zach Greene is a Clean Energy Associate with the U.S. Energy Program at WRI. He supports local governments and large energy buyers in achieving their clean energy and climate goals. This includes leading cohorts on innovative clean energy procurement strategies, advising coalitions engaging on wholesale market issues, and advancing low-income community solar opportunities.

Contact: zach.greene@wri.org

Joseph Womble is a Research Analyst with the U.S. Energy Program at WRI. He provides research and facilitates local engagement to advance the clean energy transition among municipalities and large energy buyers. This includes educating municipalities and business districts on renewable energy opportunities in their jurisdictions, forming creative solutions to increase low-income participation in community solar programs, and providing support to cities looking to increase renewable energy within wholesale markets.

Contact: joseph.womble@wri.org

Katrina McLaughlin is a Research Analyst with the U.S. Energy Program at WRI. She supports WRI’s work on clean energy, electricity market design, and transportation electrification. This includes tracking federal legislative and regulatory developments as well as identifying federal funding opportunities for local decarbonization. She also supports state policy work as part of WRI’s Electric School Bus Initiative.

Contact: katrina.mclaughlin@wri.org

Lori Bird is the U.S. Energy Program director and holds the Polsky Chair for Renewable Energy within the global Energy Program at WRI. She focuses on decarbonization of the power sector by utilities and large buyers as well as transportation electrification.

Contact: lori.bird@wri.org

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