How do you solve a problem like interconnection?

In June 2022, the US Department of Energy (DOE) launched the Interconnection Innovation e-Xchange (i2X) to convene stakeholders – grid operators, utilities, federal, state, and Tribal governments, clean energy developers, energy justice groups, researchers, and others – to identify interconnection barriers, share best practices and lessons learned, and test innovative solutions to specific interconnection challenges.

Where we are now

Grid interconnection, the process of connecting generators or energy storage to the electric transmission or distribution grids, has emerged as one of the most significant obstacles to the energy transition in the United States. For developers, long queues of projects requesting interconnection agreements and unknown or very high interconnection costs can result in lengthy delays and, potentially, in project cancellations.

At the same time, the large number of interconnection applications for renewable projects has challenged grid operators tasked with maintaining the safety, reliability and security of the grid. The complexity of interconnection makes it what is referred to in system dynamics literature as a “wicked problem”—a multifaceted challenge that has many different causes, many stakeholders, and no single solution.

Generator interconnection procedures were designed for a grid powered by a smaller number of large, centralised generators, primarily interconnected to the transmission grid. The increased number of smaller, decentralised renewable systems with different technical characteristics being interconnected to both the transmission and distribution systems has strained existing procedures and introduced new grid challenges.

While the Federal Energy Regulatory Commission (FERC) and transmission grid operators, as well as state regulators and distribution utilities, have adopted a range of reforms to interconnection policies, procedures, and tools, more work is required to keep pace with the changing technologies and generation mix needed for the energy transition.

The mission of DOE’s i2X programme is to enable simpler, faster, and fairer interconnection for clean energy generation and energy storage, while enhancing the reliability, resilience and security of the grid. More than 530 organisations, representing the full range of interconnection stakeholders, have joined i2X as partners and thousands of people have actively engaged in i2X workshops.

i2X is gathering baseline information to track progress and identify successful strategies, as well as providing technical assistance to support stakeholders in improving interconnection practices and processes. i2X is also developing two roadmaps, one focused on the transmission grid and the other on the distribution system grid, to systematically identify solutions to improve interconnection processes.

The interconnection process

Interconnection processes vary significantly, depending on the geographic location of the proposed generator or energy storage asset and whether it is accessing a lower-voltage distribution system, higher voltage transmission system (bulk power system), or the in-between (sub-transmission).

Notionally, however, these processes have similar steps. A customer—the entity that wants to interconnect a new generator or energy storage asset, usually a private developer—submits an interconnection request to the relevant grid operator. Depending on the point of interconnection, the grid operator—either a transmission provider or a distribution utility—places the interconnection customer’s request into its interconnection queue.

Through a series of technical screens or detailed interconnection studies, the grid operator will evaluate how the proposed generator would affect its grid system’s safety, stability, power quality and reliability. For most small-scale generators below a certain capacity threshold (e.g., 50kW) in distribution systems, the studies are fast-tracked through technical screens to grant interconnection agreements. In some cases, upgrades to the grid system might be needed to connect the generator safely and reliably. As proposed generators advance through the interconnection queue with detailed studies, they may have additional requirements.

At this stage, customers will also obtain more accurate information from the grid operator about the interconnection costs associated with the project. Interconnection costs can include local facilities costs and broader network upgrade costs to ensure a safe and reliable grid system. Interconnection customers typically must pay upfront for all or some portions of the facilities and network upgrade costs. An interconnection customer can withdraw its request from the queue at any point, which may affect the remaining interconnection requests, triggering a restudy or changing interconnection costs for others in the queue.

Once an interconnection customer completes all the steps and requirements of the interconnection evaluation process, the customer will sign an interconnection agreement. After the agreement has been signed, network upgrades have been made and the generator has undergone inspection and testing, the new facility is then ready to be energised and begin delivering power to the grid.

FERC, which is responsible for regulating the interconnection process for the interstate bulk power system, recently issued the first major change to its interconnection procedures in nearly two decades. This update, FERC Order 2023, is an important step to standardising interconnections across the country and speeding the process of clearing transmission interconnection queues. FERC Order 2023 makes several significant reforms to current procedures, the central of which is to implement a “first ready, first-served” cluster study process. This reform requires that transmission providers study potential new generation in groups by location and time of entry to the queue, rather than reviewing projects one by one.

The order also requires customers to pay higher deposits, demonstrate site control and pay withdrawal fees; fines grid operators and utilities that do not adhere to the interconnection studies timelines; and allows co-located resources, such as solar-plus-storage projects, at a single point of interconnection, to submit one interconnection request rather than requiring separate queue entries.

Rising transmission interconnection costs and delays

The total capacity in transmission interconnection queues is growing annually. As of the end of 2022, more than 1,350GW of generation and an estimated 680GW of energy storage were active in the queues, as shown in the graph below, exceeding the installed capacity of the entire US power plant fleet
(~1,250GW).

Requests to connect new solar capacity (947GW) and new wind capacity (300MW) approaches what is needed to decarbonise the grid by 2035. A significant portion of this proposed capacity, however, will likely not be built: only 14% of the generator capacity requesting interconnection from 2000 to 2017 has been built as of the end of 2022.

As the transmission interconnection queues have grown, so have queue wait times. The median time from the submission of an interconnection request to an interconnection agreement has increased sharply since 2015, reaching 35 months in 2022, as shown in the graph below.

Costs have also grown over time in five wholesale US electricity markets, though they vary considerably by location, as shown in the graph below. Most of the cost increases were due to network upgrades that were determined to be necessary to connect new generation safely and reliably. In some cases, the costs of interconnecting to the grid can become high enough to jeopardise the economic feasibility of a project, which can influence a developer’s decision to withdraw from the queue.

Projects that withdrew had much higher interconnection costs than active or completed projects. In PJM’s queue, for example, projects in the queue in 2022 had mean interconnection costs of US$240/kW of capacity, while projects that withdrew between 2020 and 2022 would have cost US$599/kW. When potential energy generators withdraw from the interconnection queue, those network upgrade costs may then be imposed on other developers—which can lead to a cascade of withdrawals of potential renewable energy projects.

With almost 3,000 distribution utilities that manage interconnection to distribution system grids in the US, data on distribution interconnection timelines and costs are more dispersed than for the transmission grid, and in most cases are not collected or released publicly. A few states require the collection and publication of this data (e.g., CA, HI, NY, MA), but most do not. DOE is exploring options to collect data on the interconnection timelines and costs of distribution grids.

Where we need to go

Transmission roadmap

In October 2023, after extensive stakeholder input, DOE released a draft transmission interconnection roadmap, which is intended to serve as a guide to key actions that stakeholders should take in the next five years and beyond to implement solutions to interconnection challenges and to clear the existing backlog of solar, wind and energy storage projects in the queue. It also establishes high-level, measurable targets for 2030 to provide a vision for interconnection reforms and gauge progress.

Interconnection reform is a group effort. Thus, the solutions in this roadmap describe actions for a range of different actors. For each solution in this roadmap, specific stakeholder groups are identified and assigned suggested actions. DOE has multiple roles: convening stakeholders, facilitating solution adoption, providing technical assistance, supporting the research community and potentially becoming a solution provider. The draft roadmap is organised into four primary goals and identifies more than 30 solutions that are intended to be a collection of viable strategies rather than a rigid package of prescriptive fixes, sampled in the table below.

While the roadmap solutions align with current regulations, it introduces additional ideas to support implementation and interconnection process evolution. Each solution has a timeframe that indicates how long the solution might take to implement: short-term (1-3 years); medium-term (3-5 years); and long term (>5 years).

1. Increase data access and transparency: Improvements to interconnection data transparency, beyond those in FERC rules, would help to improve interconnection customers’ ability to site potential projects and better enable third-party modeling and more process automation, as well as benchmarking, tracking and auditing of interconnection processes and reforms. Notably, this includes increasing transparency around timelines, costs and delays in the period after an interconnection agreement is signed. Increasing transparency should generally increase fairness, equity and competition in the interconnection process while lowering the number of non-viable, ultimately withdrawn projects and increasing the proportion of high-quality, well-sited projects in the queue.
2. Improve process and timing: Interconnection backlogs and delays are often the result of rapid growth in interconnection queues, inefficiencies in interconnection processes, and staffing constraints. Interconnection queue volumes in the US are likely to be large and potentially volatile for the foreseeable future. Streamlining interconnection processes and improving the viability of projects applying for interconnection as the total volume remains high should help mitigate existing queue backlogs and decrease the time required to interconnect, all while maintaining open access principles that remain central to resource development. Solutions address improving queue management practices, affected system studies, inclusive and fair processes, and workforce development.
3. Promote economic efficiency: Interconnection and transmission planning are closely related. Proposed generators not selected through long-term transmission planning may trigger the need for broader network upgrades to interconnect. How to allocate these costs has proven to be one of the most difficult interconnection challenges, requiring decision makers to carefully vet and weigh diverse stakeholder perspectives according to specific objectives. Solutions aim to improve cost allocation, enhance the coordination between transmission planning and the interconnection process and right-size transmission investment through improvements in interconnection studies that help reduce costs to consumers.
4. Maintain a reliable and resilient grid: Historically, the goal for connecting wind and solar with inverters was primarily to deliver power to the grid and they were therefore disconnected during grid disturbances. Given the growing number of inverter-based resources on the grid, these generation sources increasingly need to ride-through disturbances and support grid recovery. Requirements for ride-through, however, are not always defined and do not include performance specifications during other accompanying events on the grid. Solutions aim to reduce these gaps by updating technical requirements within interconnection studies, models and tools, while also improving industry interconnection standards.

Equity is not a standalone goal in the roadmap, because it is integral to each of the goals. Energy equity in interconnection requires intentionally designing systems, technologies, procedures and policies for all types of interconnection stakeholders, particularly disadvantaged and energy justice communities who may lack the financing, resources and capacity needed to navigate interconnection. Solutions in multiple sections specifically aim to resolve current issues of equity within the interconnection process.

The final roadmap will be published in early 2024.

Preview of distribution system roadmap

While technical requirements for transmission interconnection are mandated by FERC, interconnection on the distribution and sub-transmission systems is a patchwork of regulations, processes, timelines and costs. State-regulated electric utilities are under the jurisdiction of individual state public utility commissions (PUCs). A significant portion of the nation’s untapped renewable energy resources, however, are in rural areas that are served by more than 800 consumer-owned utilities, which have their various regulatory environments.

Distributed generation and energy storage have continued to skyrocket in growth, with the DOE estimating that the total capacity of distributed energy resources (DERs) in the United States will grow to 380GW in 2025, more than a 300% increase from the 90GW in operation in 2022. Energy storage and electric vehicle-charging infrastructure pose particularly unique challenges to the interconnection study processes used by many utilities. Interconnection processes and standards will need to evolve to handle the increasing number of requests, as well as increasing complexity of DERs, as policy and economic drivers continue to motivate significant resource development.

In response to this continued expansion, FERC adopted Order 2222 in 2020, which allows aggregations of DERs to participate directly in wholesale electricity markets. The order allows DERs to sell excess electricity to the bulk power grid, like transmission-interconnected generators already do, and requires ISO/RTOs to remove barriers to participation in these markets. Navigating this and other changes will require unprecedented coordination between transmission and distribution system operators at all levels, including system planning, standards adoption, market design, and regulation.

DOE is currently developing a DER interconnection roadmap that will identify key actions that stakeholders should take to implement solutions to interconnection challenges on the distribution and sub-transmission systems. Like the transmission roadmap, a draft will be released for public comment before it is finalised.

A few of the solutions that will be outlined in the draft distribution system roadmap include:

• Establish and maintain hosting capacity analysis (HCA) tools: Some distribution utilities have begun to develop maps that provide developers with information on where interconnection costs may be lower due to sufficient feeder headroom (hosting capacity), and where interconnection may trigger expensive upgrades due to capacity constrained feeders. While these maps can enable developers to make more informed decisions during project planning and reduce exploratory interconnection requests, issues of accuracy, granularity and timeliness of the data, as well as the cost and lack of automated processes to develop and maintain them, need to be addressed.

• Enable flexible interconnection: Historically, utilities have used physical infrastructure to expand grid capacity for interconnection by sizing capacity to the maximum generator output plus a buffer margin, often leading to costly system upgrades that address grid violations only occurring a few hours out of the year. Flexible interconnection is a strategy in which generator output is controlled and monitored in real time by the utility, and production is curtailed within an agreed set of parameters when there is a threat to system reliability or power quality. Flexible interconnection can remove the need for costly system upgrades and allow for greater grid utilisation and faster and cheaper interconnection, while having minimal impact on the economic viability of a project. While some utilities in Europe and Australia already use flexible interconnection, the approach is in its infancy in the United States and standards and guidelines still need to be developed.

• Enable alternatives for direct transfer trip (DTT): DTT is a system protection and safety feature commonly used on distribution grids to mitigate islanding and overvoltage risks from DERs. The cost and complexity of implementing DTT, however, is a significant hurdle for many DER projects and a common reason for withdrawal from the interconnection queue. Solutions include developing guidelines for alternatives to DTT and researching methods to evaluate the effectiveness of DTT deployment relative to the cost.

Interconnection challenges on the distribution grid can be particularly evident for energy justice communities, Tribes, and other disadvantaged communities that are interested in accessing the benefits of clean energy. For example, interconnection cost uncertainties or delays can derail community solar projects that make solar more accessible to all Americans, particularly to those with low-to-moderate incomes and renters. Like the transmission interconnection roadmap, solutions to address equitable interconnection on the distribution system grid will be discussed throughout the document.

Conclusion

Although interconnection is a complex “wicked problem” without a single solution, the good news is that there is a collection of viable solutions that can address the technical, market, and administrative challenges of transmission and distribution system grid interconnection. Increased and sustained collaboration among all stakeholders, as well as implementation of innovative approaches and tools, can lead to an efficient, equitable, and modern interconnection process that ensures a clean, reliable, and secure electric grid.

Michele Boyd is the programme manager of the Strategic Analysis and Institutional Support team in the US DOE Solar Energy Technologies Office. The team supports the development of analysis, tools and data resources to reduce the non-hardware (soft costs) of solar energy and accelerates learning through technical assistance programs and national partnerships.

Will Gorman is a research scientist in the Energy Markets and Policy Department at Lawrence Berkeley National Laboratory where he focuses on the integration of renewable energy into the electric power system, the economics of distributed energy resources, and the application of energy storage within electricity networks. In his work, Will particularly seeks to inform public and private decision making within the US electricity sector via economic analysis.

Diane Baldwin is a project manager at the Pacific Northwest National Laboratory. She has extensive experience leading projects in the renewable energy field as a power system engineer, energy policy analyst, and programme administrator for entities both public and private. Her work focuses on grid interconnection and integration of renewable energy and energy storage resources.

The authors acknowledge the contributions of the entire i2X team within DOE’s Solar and Wind Energy Technologies Offices, national labs (Lawrence Berkley National Lab, Pacific Northwest National Lab, and the National Renewable Energy Laboratory), and the Energy Systems Integration Group (ESIG).