Stakeholders at the Southeast Regional Transmission Planning (SERTP) meeting on June 26 in Chattanooga were presented with the 10- year forecasts for elements that influence transmission solutions. Things like demand, or ‘load forecast,’ play a large role in identifying the transmission needed to serve consumers throughout the SERTP footprint. If you look at the transmission system like the highway system, you need to make sure the grid can handle the traffic of electrons that consumers demand.
When looking at this load forecast, SERTP presents a footprint-wide forecast, rather than showing the demand forecast by Load Serving Entity (LSE). While it was conveyed to stakeholders that a demand forecast for 10 years into the future is contributed by individual LSE’s for the SERTP process, the information presented does not break out demand by the LSE. The challenge presented with this approach is that stakeholders do not get a good sense of where, and how much new demand there is being placed on the system over the ten year period that SERTP’s process plans for.
While SERTP’s current process is only looking at reliability needs over the next 10 years, they are required in the next year to develop a separate process whereby they include multiple scenarios that consider multiple drivers for transmission needs in order to comply with FERC Order 1920.
MISO’s Futures process does not provide a demand forecast per LSE, but they do give a general sense of where load is increasing, and by how much, by breaking out the load forecast by Local Resource Zones (LRZ) that generally align with state borders or analogous regions that share a lot of generation resources.
The general theme of the load forecast is dramatic growth compared to previous years. Much of this demand is driven by large data center companies which have presented increasing challenges across the footprint, and a need for additional generation as well as transmission resources.
Solar and Battery Additions, and Potential Signs of IRA Rollback Worries
Throughout the largest utilities generation assumptions, a common theme was increasing solar and battery energy storage (BESS) over the next 10 years. Southern Company (SOCO), Duke Energy and the Tennessee Valley Authority (TVA) all have significant additions of solar capacity. However, there are also commitments to building new natural gas generation.
These generation assumptions are based on generation projects that have been granted an interconnection agreement, but for some projects that may not be enough to ensure timely addition to the energy system. As it has been alluded to in recent months, demand has increased dramatically for new natural gas turbines. With this increase in demand comes an increase in wait times. According to the May EIA 840M Report, there are about 4.8GW’s of natural gas turbines in the SOCO and TVA footprints that are expected to be in service in the next five years, there could be a challenge to meeting expectations. In recent months reporting has revealed that gas turbine supply chain delays could be up to 7 years, which could delay these in service dates. When this generation comes online, it becomes a big factor in what transmission needs to get built. How power moves across the grid, and when it’s available can drive drastically different transmission solutions.
The impacts of changing policy can threaten the viability of clean and firm new generation. One of the largest pumped storage facilities in the US, the Bad Creek Pumped Storage Facility, had included an expansion in Duke Energy’s IRP which would nearly double its capacity. Unfortunately, it was stated at the Q2 SERTP meeting that this project will likely not be built, depriving the Duke system of clean firm energy. While no reason was given at the meeting, it could possibly be attributed to the proposed repeal of Technology Neutral Investment Tax Credits in the Inflation Reduction Act. Since the plant is not expected to come online until the 2033-34 timeframe, it would not qualify for a tax credit available to projects.
Preliminary Transmission Expansion
The topic that SERTP utilities spent the most time on during the meeting was a discussion of their preliminary transmission expansion plans. While the acronym SERTP contains the word ‘regional', all projects proposed in their yearly process to date address reliability issues only within the utility territories. For the process to truly be regional, it would have to propose at least one transmission project that bridges one or more utility territories. However, some trends have emerged driving large transmission solutions in the utilities in the SERTP footprint.
In the Southern Company territory, 500kV lines are a major feature in the company’s strategy to maintain reliability over the 10 year period covered by SERTP’s process. Some of these are many miles in length, and indicate the need to transfer large amounts of power from generation to load. In some cases though, there could be other reliability needs, like the ability to re-route power in the event of a large generator like the 700MW Plant Yates tripping offline.
In Duke’s territory across both Duke Energy Progress and Carolinas footprint, the maximum voltage for most solutions is capped at 230kV. This may indicate less of a priority for large energy transfers like those discussed in SOCO. It should be noted that on the day of the SERTP meeting, there was such a great concern that Duke would not be able to serve demand due to heat, that the Department of Energy granted a waiver to forego environmental regulations for power plants to run them at a higher rating. This priority for lower transfer capability in the Duke territory would seem to be at odds with pressing needs in the past week.
One notable feature in Duke’s preliminary transmission plan is the inclusion of Red Zone transmission projects identified in the Carolina Transmission Planning Collaborative. These are a response to recurring interconnection issues. There were a good number of projects included in this year’s preliminary transmission plan that are intended to allow clean generation to come online at lower interconnection costs to meet the state of North Carolina’s Carbon Plan.
Transparency…Again
Stakeholders in the SERTP process have, unfortunately, become accustomed to a lack of access to meeting data. During the Q2 meeting, stakeholders requested access to the slide deck and other meeting materials ahead of time - to give adequate time to prepare questions for the meeting and around projects presented - and requested extra time to provide feedback on the projects presented during the meeting. The meeting’s hosts said that while they understood the challenges that come with seeing the materials for the first time that morning and trying to synthesize feedback during the meeting, stakeholders were ultimately told no. They noted that the notification to submit comments is 10 days ahead of the meeting and they cannot make exceptions.
Another stakeholder requested access to historical load forecast data to help better make year-over-year comparisons, but stakeholders did not receive a commitment from SERTP to include this information at future meetings.
SREA has called for improved data access and transparency from SERTP before. In comments submitted in May, SREA noted that for meaningful stakeholder contribution to occur during these meetings, access to planning models and data is essential. SREA also recommended in those comments that meetings be recorded, and that meeting materials and minutes should be provided in a timely fashion. In a wrap up of the August 2024 meeting, SREA Executive Director Simon Mahan noted: “Stakeholders noted that many of the materials provided before the meeting on the SERTP website would appear, then disappear. Some stakeholders were unable to access the hundreds of pages of materials before, and during, the meeting. Without early access to the volumes of information to be presented at a meeting, it’s often difficult, if not impossible, to adequately prepare for a meeting.”
The Q2 meeting showed there’s still room for improvement when it comes to stakeholder access and transparency.
Nearly a week after the SERTP meeting, the materials from the meeting still haven’t been posted. UPDATE: Materials were posted the afternoon after this blog was posted.
Order 1920 and Beyond
The SERTP Q3 meeting will be held virtually and is scheduled for September 23. It was stated at the Q3 meeting that there will be an additional Order 1920 Stakeholder meeting held near the end of August. The Q3 meeting did not discuss Order 1920 directly, but it was alluded to in discussions around the core assumptions of load and generation during the meeting as providing the potential for more robust consideration of transmission needs for into the future.
For SREA’s take on scenario planning in the SERTP footprint, view our blog here!
