Christopher Hailstone brings decades of expertise to the complex world of power grid regulation and utility management. As a specialist in electricity delivery and grid security, he has become a leading voice on how to modernize an aging infrastructure to meet the demands of a decarbonizing economy. In this conversation, we explore the emerging landscape of Surplus Interconnection Service (SIS), a regulatory pathway that allows new energy resources to plug into existing grid connections, bypassing the notorious multi-year bottlenecks of traditional interconnection queues.
We delve into the technical and financial mechanics that make surplus capacity a game-changer for developers, particularly when comparing the “brownfield” advantages to the soaring costs of new builds. Our discussion covers the legislative shifts in states like Indiana and Virginia, the operational nuances of hybrid gas-and-solar sites, and the specific market barriers that currently prevent the country’s largest grid operators from fully realizing this potential.
Standard interconnection reviews often take years, while surplus interconnection service can be completed in less than twelve months. How do the infrastructure requirements differ between these two paths, and what specific technical hurdles should developers expect when integrating storage at existing “brownfield” sites?
The primary difference lies in the utilization of existing “interconnection rights,” which essentially allow a new project to piggyback on the electrical handshake already established with the grid. In a standard review, engineers must simulate how a new project affects the entire regional network, often triggering the need for massive new substations or high-voltage lines that take years to permit and build. With SIS, we are focusing on “brownfield” development, meaning we are adding assets like battery storage to a site that already has the physical transformers and wires in place. The technical hurdles at these sites usually involve ensuring the new equipment doesn’t exceed the original thermal limits of the existing connection. Developers must carefully manage the physical footprint to avoid interfering with the original plant’s operations while upgrading control systems to balance two different types of generation simultaneously.
Some solar projects utilizing surplus capacity face interconnection costs under $1 per kilowatt, compared to over $330 for traditional builds. What specific equipment or grid upgrades are typically bypassed to achieve these savings, and how do these financial margins change the risk profile for early-stage developers?
The cost disparity is staggering, and it stems from bypassing the “network upgrades” that usually sink a project’s budget, such as rebuilding miles of transmission lines or installing multimillion-dollar circuit breakers. In the Kansas example, the $0.71/kW cost reflects a scenario where the developer simply plugs into an underutilized outlet, whereas the $333.42/kW cost likely includes a share of a massive regional grid expansion. For an early-stage developer, this shifts the risk profile from “prohibitive” to “highly attractive” because it eliminates the uncertainty of the interconnection “blind bid.” When your upfront capital expenditure for grid access drops by 99%, you can move from a feasibility study to a final investment decision in a fraction of the time. This financial breathing room allows for more aggressive deployment of storage, which helps stabilize the grid without the developer needing to secure astronomical amounts of venture capital.
New state mandates require utilities to assess available capacity at existing plants and incorporate surplus interconnection into long-term resource plans. How do these requirements change the way utilities prioritize their internal queues, and what steps should regulators take to ensure these assessments are transparent to third parties?
Legislation like the FAST Act in Virginia and SB 240 in Indiana forces a fundamental shift in utility planning by requiring companies like Dominion or NIPSCO to treat “spare capacity” as a formal resource. Previously, this capacity might have sat idle and unmapped, but now utilities must analyze and report this potential in their integrated resource plans (IRPs). To ensure transparency, regulators should mandate that these utilities publish “heat maps” or public databases showing exactly where surplus headroom exists at each power plant. Without this public-facing data, there is a risk that utilities will prioritize their own internal projects for these “fast-track” slots while leaving third-party developers in the dark. Clear, standardized reporting by 2030, as mandated in Indiana, ensures that every new plant proposal must first answer why an existing site couldn’t be used instead, creating a “brownfield-first” mentality.
While some grid operators have gigawatts of surplus requests in their queues, others have approved only a handful of projects. Why does the requirement to participate as a single hybrid resource create such a significant barrier for financing, and what specific market rule changes would resolve this?
The “single hybrid resource” rule, particularly in the PJM Interconnection, is a major administrative anchor that prevents projects from getting off the ground. When a grid operator forces an existing wind farm and a new battery to act as one single entity, it often requires the developer to renegotiate every original contract, from power purchase agreements to complex financing terms. This is “essentially not workable” because it disturbs the long-term financial stability of the original project just to add a new component. To resolve this, market rules should follow the lead of MISO and SPP, where projects are allowed to maintain separate identities for market participation while sharing a physical connection. By treating them as separate projects that simply share a “pipe” to the grid, developers can finance the new storage unit independently without triggering a legal overhaul of the original asset.
Adding energy storage to a wind or solar facility can transform intermittent generation into a dispatchable resource with higher capacity value. Could you walk through the operational challenges of managing a combined gas-fired peaker and solar site, and how does this integration affect daily power delivery?
Integrating solar at an infrequently used gas-fired peaker plant is one of the most elegant ways to maximize existing infrastructure. The primary operational challenge is the “hand-off” between the solar array, which might provide bulk energy during the day, and the gas turbines, which are called upon during peak demand or when clouds roll in. By combining these, you transform a site that might only run 10% of the year into a facility that delivers clean power daily. This integration creates a more resilient delivery profile because the solar generation can offset the fuel costs of the gas plant during the day, while the gas plant provides the firm reliability the grid needs at night. It turns a “backup” asset into a primary workhorse, ensuring that the existing transmission wires are carrying electrons consistently rather than sitting empty for most of the day.
What is your forecast for surplus interconnection?
I forecast that surplus interconnection will become the primary “fast-track” lane for the American energy transition over the next five years, potentially unlocking up to 150 GW of new supply in PJM alone. As states continue to pass mandates like those in Indiana and Virginia, we will see a massive wave of battery storage additions at existing thermal and renewable sites because the speed-to-market is simply unbeatable. While PJM currently lags behind MISO’s 8,960 MW of surplus requests, the pressure from state lawmakers will eventually force a modernization of their “hybrid” rules to unlock the gigawatts currently sitting in limbo. We are moving toward a future where “reclaiming” existing grid capacity is seen as just as important as building new lines, fundamentally changing how we value every acre of existing power plant land.
