The co-location of load with generation has become a major focus in the electric utility industry, driven by technology companies seeking to bypass generator interconnection queues. While this approach offers potential benefits, it raises challenges like cost allocation and regulatory inconsistencies, particularly between behind-the-meter and in-front-of-the-meter loads.
Historical missteps, such as Entergy’s speculative “industrial renaissance” and Foxconn’s unmet load projections, highlight the risks of overcommitting to large infrastructure projects. Instead of pursuing unproven nuclear technologies, regulators should prioritize immediate, scalable solutions like batteries, demand response, and rooftop solar to ensure a reliable and efficient grid.
The co-location of load with generation has become a prominent topic in the electric utility industry, spurred by recent announcements from technology giants like Microsoft, AWS, and Meta. These companies have drawn attention to longstanding issues with generator interconnection queues at Regional Transmission Organizations (RTOs), as their Power Purchase Agreements (PPAs) with renewable energy developers faced delays. Developers, in turn, had overwhelmed interconnection queues with multiple, often speculative, requests.
In response, most RTOs have transitioned from serial studies to cluster studies for processing generator interconnections. However, the effectiveness of this shift varies, and no RTO has yet identified a definitive solution to the backlog. Efforts are ongoing, under close scrutiny from the Federal Energy Regulatory Commission (FERC), as stakeholders strive to address these challenges.
While generator interconnection queues remain a persistent issue, load interconnection has emerged as an additional challenge over the past two or three years. Until recently, the Midcontinent Independent System Operator (MISO) handled load interconnections through its Expedited Project Request (EPR) process. Under this approach, the MISO Transmission Owner received requests from load interconnection customers and flagged them for MISO’s analysis. MISO then conducted studies to assess transmission system impacts and reported the costs of necessary upgrades to accommodate the load.
In recent years, the number of EPRs at MISO has surged, reflecting the growing demand for large-scale load connections. However, Entergy’s “industrial renaissance” EPR requests from 2014 serve as a cautionary tale. Entergy had requested transmission studies and initiated transmission projects based on anticipated industrial load growth, only to withdraw the requests later when the expected loads failed to materialize.
As large load interconnections become more commonplace, the lessons from Entergy’s industrial renaissance highlight the risks of rushing into transmission build-outs based on speculative assumptions. Strategic and cautious planning is essential to avoid overbuilding or underutilizing transmission infrastructure.
A similar situation unfolded in Wisconsin in 2017, when a large Taiwanese semiconductor manufacturer, Foxconn, proposed significant operations in the region. Despite initial promises of substantial load increases, the projected demand never materialized, leaving planned infrastructure underutilized.
Technology companies may argue that their situations differ from those of industrial companies in Louisiana or semiconductor manufacturers like Foxconn in Wisconsin. While this may hold some truth, the renewed focus on reviving old nuclear plants, such as Three Mile Island, and pursuing contracts with unproven nuclear technologies raises concerns. These actions suggest we may be repeating the same mistakes—overestimating future load growth and committing to costly infrastructure projects without adequate certainty—when faced with large, anticipated loads on the electric grid.
Recent news suggests that Enron is reentering the business world, a reminder of the boom-bust cycles that have shaped the energy industry. (Editor’s note: We don’t really know what the whole Enron thing is about yet- could be a crypto scam- keep your head on a swivel, people.) The collapse of Enron in the early 2000s marked a significant downturn, as it took two years for the Independent Power Producer (IPP) market to completely unravel.
Fast forward to 2018, nearly two decades later, the renewable energy market experienced rapid growth, bringing its own set of challenges. This explosive expansion has contributed to the generator interconnection queue issues discussed earlier, highlighting the recurring challenges of scaling new technologies and markets responsibly.
Electric utilities face significant risks if they uncritically accept optimistic load growth assumptions, whether driven by technology companies or industrial enterprises. One major concern is the growing focus on nuclear energy, driven by its appeal as a carbon-free, 24/7 energy source. However, this infatuation risks prioritizing large capital projects with limited short-term benefits, often at the expense of more practical and immediate solutions like demand response.
The concept of co-locating load with generation might seem like an innovative way for technology companies to bypass the bottlenecks of generator queues and load interconnection studies, which often reveal the need for costly and time-consuming transmission upgrades. From their perspective, this approach appears to solve their pressing issue of meeting the ever-growing data demands of their customers. Yet, this rush toward co-location could lead to unintended consequences, especially if it overcommits resources without clear, reliable returns.
The co-location trend has brought attention to a longstanding issue in the electric utility sector: cost allocation. Previously discussed primarily in the context of generator and supply-side projects, the question of who pays for transmission upgrades has now surfaced on the demand side as well. The framework for addressing these costs in generator interconnection projects has been shaped by a series of FERC Orders, including Orders 890, 1000, 2003, and most recently, 1920.
These policies aim to balance the need for reliability and economic efficiency in transmission planning. However, as load interconnection and co-location become more prominent, stakeholders must grapple with how these principles apply in scenarios where generation and load are tightly integrated.
Large load interconnection requests and co-located projects by technology companies are exposing the complexities of behind-the-meter (BTM) versus in-front-of-the-meter (IFM) load and the challenges of connecting to the transmission grid versus the distribution grid. As highlighted in the analysis paper, if FERC issues an Order addressing these issues, it would apply uniformly across the regions served by FERC-jurisdictional RTOs.
However, significant regional differences remain in how Network Integration Transmission Service (NITS) is applied. For example:
- CAISO and NYISO use actual energy withdrawals as billing determinants.
- ISO-NE, MISO, and SPP rely on monthly hourly peaks.
- PJM uses a zonal annual peak, as noted by the Analysis Group.
Similarly, most RTOs (CAISO, ISO-NE, NYISO, and PJM) allow netting for Behind-the-Meter Generation (BTMG). In contrast, MISO and SPP only permit netting when loads are entirely served by BTMG.
Rather than addressing these nuanced regulatory differences to create more uniform and effective policies, the industry appears to be shifting its focus to the next “shiny object”- nuclear power. This shift risks overlooking the critical need for consistent and practical solutions to the challenges of load interconnection and transmission planning.
Instead of allocating time and resources to unproven nuclear technologies, electric consumers would benefit more from state and federal regulators prioritizing readily available solutions. These include electric storage resources like batteries, grid-enhancing technologies such as dynamic line ratings, and distributed energy resources like demand response and rooftop solar. Unlike nuclear power, these technologies can be deployed within months, not years, offering immediate improvements to grid reliability and flexibility.
Shifting focus away from these proven, deployable solutions to nuclear energy as the sole 24/7 emissions-free option risks repeating past mistakes. Lessons from the post-Enron collapse, Entergy’s industrial renaissance in Louisiana, and the Foxconn project in Wisconsin highlight the dangers of overcommitting to speculative or unproven projects. By focusing on practical, near-term innovations, regulators can ensure a more reliable and cost-effective future for the grid.
