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.

This working paper examines how certain policies, rules, and practices within the regional transmission organizations (RTOs) may create both barriers to and opportunities for the expanded uptake of renewable energy in those regions. Although RTO-operated markets and regional transmission planning offer a critical foundation for expanding these resources, certain rules and processes may impede renewable energy deployment.

These wholesale market issues, in turn, can affect the ability of a local government to achieve its clean energy goals. 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 September 2021, nearly 200 local governments had committed to using 100 percent renewable energy in their communities (Sierra Club n.d.). This paper highlights characteristics of RTOs that may affect achievement of these goals and presents issues on which local governments may wish to engage.

Although this paper identifies and explains certain barriers to and opportunities for renewable energy, it is not intended to serve as a guide to engagement for policymakers. Local governments and other customers interested in influencing decisions and outcomes in wholesale markets should consider a previous World Resources Institute (WRI) working paper: “Local Government Voices in Wholesale Market Issues: Engagement Approaches for Decarbonization” (Ratz et al. 2021). In tandem, these two papers can help local governments and other interested stakeholders identify issues in their RTO on which to engage and what engagement pathways exist.

This paper focuses particularly on solar energy as well as hybrid solar-plus-storage installations, which are increasingly cost-competitive and prevalent in these wholesale markets. However, many of the barriers and opportunities raised around solar energy also pertain to other renewable energy sources. Although this paper provides high-level considerations around certain issues in wholesale markets, it does not provide in-depth analysis of each issue, nor does it intend to explore all potential barriers and opportunities that exist. We recognize that a host of other policies and processes beyond those covered affect solar deployment within wholesale markets. Additionally, this paper does not address factors outside of wholesale market control that may also significantly impact solar deployment, such as state and local clean energy regulatory policy and siting requirements, tax policies, and other environmental rules.

For the purposes of this paper, a barrier is defined as an obstacle to the deployment of solar or renewables once an independent power producer (IPP) or utility has decided to deploy renewables within a wholesale market. Similarly, an opportunity is defined as a market characteristic that increases the likelihood of solar or renewables being interconnected successfully after a utility or IPP has decided to deploy them. Whereas some barriers and opportunities are clear and agreed upon, even if proposed solutions differ, many barriers are not agreed upon across wholesale market operators, renewable energy advocates, independent market monitors, and other parties. In addition, many of the identified barriers also exist—and, in certain instances, are more severe—in non-RTO regions. We have not addressed all instances where this is the case because this paper focuses on clarifying the issues and processes within RTOs.

The research to support the development of this paper, including the literature reviewed and experts consulted, primarily focused on the Independent System Operator New England (ISO-NE), the Midcontinent Independent System Operator (MISO), and the Electric Reliability Council of Texas (ERCOT). These markets are covered in detail in the appendixes. Other wholesale markets, including the California Independent System Operator (CAISO), the New York Independent System Operator (NYISO), the PJM Interconnection (PJM), and the Southwest Power Pool (SPP), have some similar features and also might have different barriers to and opportunities for renewable energy than the wholesale markets examined in this paper.

Methodology

The information presented in this working paper was developed through expert interviews, conversations with local governments and other stakeholders at WRI-led events, and a literature review of previous research on wholesale markets and barriers to solar within them.

The authors conducted a series of interviews with energy experts familiar with the overall wholesale electricity market landscape as well as the specifics of ISO-NE, MISO, and ERCOT (see Acknowledgments). These expert interviews highlighted unique features of each RTO and critical barriers to successful deployment of solar energy, providing the focus for subsequent research.

Beyond these formal interviews, the authors also engaged with members of a WRI-convened Advisory Committee made up of wholesale market and local government experts as well as with members of the PJM Cities and Communities Coalition (Box 1). The authors used these discussions to solicit input on additional barriers and opportunities within markets and to get feedback on the issues raised in the formal expert interviews.

To affirm the importance of and build out the issues highlighted by interviewees and stakeholders, the authors conducted an extensive review of written material on the functions and responsibilities of markets, current events within RTOs and at the Federal Energy Regulatory Commission (FERC), and analyses of future considerations for RTOs, FERC, and their stakeholders. This review included, but was not limited to, wholesale market publications, annual market monitor reports (specifically for ERCOT, ISO-NE, and MISO), and testimony and filings within official proceedings.

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).

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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