Sunrise in the East

How PJM is incorporating a large amount of solar while maintaining grid reliability

EPRI Journal: What grid reliability challenges are you concerned will begin to appear due to all the expected solar plant interconnections?

Seiler: We are inundated with renewable projects, whether they’re solar, wind, or a hybrid project with batteries. Most of the proposed solar generation is on the sub-transmission system. Compared with the large central station generation paradigm of the 1950s, ’60s, and ’70s, the proposed generation in our queue is much closer to major load centers and much more distributed. In some cases, it’s on the distribution circuits that serve loads. When these solar systems switch on and off or ramp up and down, that can lead to challenges for some customers, such as power quality impacts and transients, which are momentary voltage and current spikes from switching devices on and off.

We’re also seeing concentrations of solar power in certain areas—on the scale of hundreds of megawatts—that is flowing up onto the transmission system. The transmission system has to be able to accommodate those flows so far. These solar systems are intermittent and not dispatchable, meaning we can’t turn them on and off quickly. Where there are large concentrations, we need to understand the grid impacts and how to manage them. I expect that this will involve the development of additional tools and processes to study.

EJ: Are there locations of particular concern?

Seiler: We have a number of areas in our system with older transmission lines or substations. Based on the penetration of solar and resulting grid impacts in those areas, we may decide to replace some of that aging infrastructure. We are looking for synergies in certain areas with a combination of aging infrastructure, concentrations of solar, and transmission grid impacts to determine the most cost-effective upgrades needed to accommodate solar interconnections reliably.

EJ: Are there early signs of these challenges emerging?

Seiler: In some areas in the southern part of our system with large concentrations of solar connected to distribution lines, we’ve seen megawatts of power flowing not to the load, but up through the distribution system, through transformers, and into the sub-transmission or even the transmission system at times. We have energy management systems that continuously monitor the flows across our system. We made these observations on sunny days during light load periods like in the spring or fall. To accommodate these power flows and stay within our limits, we move dispatchable generation up and down as needed. We may take combustion turbines offline or ramp down combined-cycle gas units. But we don’t have a high enough solar penetration yet to cause any significant challenges to our system.

EJ: What solutions are you considering?

Seiler: It’s going to be a comprehensive set of solutions—grid modernization, enhancing the existing capabilities of the transmission system, better forecasting, new procedures, and new analytical tools. There’s no silver bullet that’s going to meet all our needs.

We’re refining our current solar forecasting tools and analytics to help us to predict when the sun is going to be shining. This includes integrating our solar and wind forecasting tools with our weather forecasts to better refine PJM’s load forecasting accuracy using neural net models.

With solar quickly ramping up and down, our control room will be prepared with new tools to monitor and control the grid and to integrate solar forecasts into our day-ahead market and real-time operating systems. We are looking at grid-enhancing technologies to help integrate solar, such as carbon core conductors to increase transfer capability on existing corridors, smart valve technologies to move power from one transmission line to another , and technologies to monitor that distribution system to a deeper level of granularity. Where we have large concentrations of wind and solar, we will need to upgrade, rebuild, and modernize transmission lines to reliably move power to the load.

As far as controlling the operations of solar plants, we can disconnect them if needed for reliability or force them offline by sending negative price signals. As we get more experience with how solar plants impact power quality for customers, we might use reactive control devices like static VAR compensators that can help provide reactive support and stability.

EJ: Who will pay for these solutions?

Seiler: This is a hot topic right now. Under our current generation interconnection process permitted by FERC [Federal Energy Regulatory Commission], we use an approach called participant funding. This means that if you’re a generator, and you inject megawatts into the system and cause reliability concerns, you’re going to pay to reinforce the system to mitigate those concerns. FERC is considering changing this existing paradigm so that the entities that benefit from the new generators pay instead of generators themselves. The beneficiaries include the load and customers who receive the power.

Several months ago, we started a series of workshops with our stakeholders—which include transmission owners, distribution utilities, and developers that seek to interconnect renewable energy plants to our system—to examine the different avenues by which we could pay for generation interconnection projects. We developed six different cost allocation models.

For example, under one model, a state would pay for grid upgrades that are needed to accommodate solar and wind deployment in support of the state’s renewable portfolio standard. This model is called a state agreement approach. We are already using this approach with New Jersey, which wants to interconnect 7500 megawatts of offshore wind to our system. New Jersey has entered into an agreement with us to advance state public policy goals, and its ratepayers will pay for the transmission upgrades to accommodate that wind.

Another approach is called the subscriber model, in which the subscribers—meaning the companies that request solar project interconnections to a particular area impacting a particular transmission line—pay for a certain percentage—50% or 75%—of the upgrades to reinforce that line, and the beneficiaries of those projects may pay the remaining cost. We’re currently vetting the six models with our stakeholders.

EJ: How can energy storage help?

Seiler: We’re looking at the concept of energy storage as a transmission asset. This involves deploying storage systems on the transmission grid and configuring them to inject or absorb power to help manage power flows on transmission lines and improve reliability. This can potentially defer transmission grid infrastructure upgrades or serve as an alternative to them. We’re exploring what performance indicators—like injection duration—would be needed to reliably interconnect storage and how storage owners would be paid for the reliability services they’re contributing to the transmission grid. When storage is connected to solar plants, you can significantly increase their capacity factors. That increases the generation availability to the system and makes solar more feasible to build and increase revenues in our capacity and energy markets. Solar plant operators would get paid for more megawatts.

EJ: What are the benefits of integrating solar plants?

Seiler: A grid with more generation resources that are more distributed and closer to load centers will be more capable of supplying power during peak or stressed times and may reduce the amount of additional transmission infrastructure that is needed in certain geographical areas. Integrating solar also supports the decarbonization of our system.

EJ: With more solar plants being deployed, are more long-distance transmission lines needed to help grid operators across North America share resources?

Seiler: Connecting regions with long-distance transmission can have many benefits. It can enhance the ability to share generation when needed, leverage the weather, generation, and load diversity, and support grid stability. But the process of siting a long transmission line is very labor-intensive and expensive, and the lines themselves are very expensive. There’s also the issue of who’s going to pay for the line. We can all sit down at a table and evaluate the need for regional transmission lines using a number of criteria, but oftentimes, if there’s no driving reliability need, the stakeholders who have to pay for them ask, “Why do I have to pay for this if there’s no reliability violation?”

You’ve got to be very surgical about where you put new lines because of the impact on landowners and on customer rates. In some areas, for example, like the Midwest, where you have large concentrations of wind, it makes a lot of sense to drive that wind through a power line to the large load centers. But for other parts of the nation, it may not make as much sense.

We already have a number of tie lines that connect PJM’s system with adjacent grids to the south, north, and west. Grid operators in different regions lean on one other when they have stressed conditions like the cold weather event in the Midwest in February of 2021 or during a capacity deficiency. During the February event, PJM sent over 15,000 megawatts of power to the Midwest through our existing tie lines.

EJ: With all the new solar being proposed, PJM’s interconnection study queue is much longer, stretching review timelines for new solar projects and increasing uncertainty about if and when these projects will be built and how much it will cost to interconnect them and mitigate their grid impacts. How is PJM addressing these challenges?

Seiler: This has also been a hot topic for us for about a year now. We’re hearing the concerns from transmission owners, developers, and other companies that seek to interconnect solar to our system. We’re working with all of our stakeholders to reform the interconnection process.

There are several fundamental issues that we’re trying to address through interconnection reform. Our queue volume has quadrupled in the last three years, and we’ve been adding staff to help process these requests. The participant funding policy of allocating costs to the entity that causes reliability concerns has been problematic because we may have 20, 30, even 40 different solar projects connecting to the same transmission facilities—which makes it difficult economically for the first generator who causes the reliability issue to pay for the necessary transmission upgrades. The transmission owners, who do the engineering studies for the needed transmission facilities, are overloaded with the volume as well. And some of our developers are part of the problem. What I mean by that is that we have developers who may have the money to build two projects, and they’ll submit 10 or 12 projects to us. This is overloading our queue. We need to make sure that we are getting real projects.

We’ve been too accommodating over the years. We’ve allowed multiple points of interconnection for the same project. We’ve allowed developers to delay their project by up to a year, sometimes even up to three years, if there are no impacts on other generators in the queue. Some of those projects are delayed because the developer is trying to sell their queue position or the project and suspends the project for a year or two. We all have a hand in this. It’s going to take a village to clean this up. We have alignment with our stakeholders on two needs: cost certainty to interconnect and the time in the queue.

One change under consideration would be to prohibit developers from suspending their projects. Our suspension provisions were put in place in the late 1990s for large combined-cycle natural gas units that had to go through extensive permitting processes. A suspension option gives these projects extra time to clear these permitting hurdles. Solar and wind developers have different permitting requirements, and the obstacles are not quite as high. Hence, you don’t need the suspension provisions. We’re also going to increase the application cost and the cost of staying in the queue. Projects will need to pay more to stay in the queue and even to advance through the queue. Overall, our stakeholders have been very supportive of the needed changes, and we want to simplify the interconnection process. We’re planning to propose changes to FERC by the end of this year.

EJ: Have the experiences of other grid operators been instructive?

Seiler: The ISOs and the RTOs across North America have frequent discussions about planning, operations, and events occurring in their systems. The most recent example is the February outages in Texas. We want to understand this and other events and see what lessons might apply to our system. We all share our experiences quite freely because we’re all in this together. We want everybody to be successful. If one grid operator isn’t successful, the others aren’t going to be successful either. We also try to learn from what’s happening in Europe, Australia, and other parts of the world. We are in the middle of a major transformation in the power industry and will need to examine and implement new tools and processes. This is the beginning of the journey, and we’re all going to be learning from each other.

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