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by SREA Transmission Director Andy Kowalczyk  There’s a growing focus on electric transmission at the federal level. The Department of Energy’s (DOE) Grid Resilience and Innovation Partnerships program has allocated about $5.6 billion in funding across the country to strengthen the grid. Additionally, they’ve identified National Interest Electric Transmission Corridors (NIETCs) to accelerate the development of transmission lines that provide economic and reliability benefits nationwide. On Capitol Hill, permitting reform, including transmission, has gained attention with a bipartisan bill from Senators Manchin and Barasso. However, this high-level interest in transmission overlooks a fundamental truth: federal support alone won’t result in necessary transmission projects. At least not without the backing of state decision-makers. Although the DOE’s current funding for transmission is significant compared to previous allocations, it falls short of addressing the projected changes in the power industry over the coming decades. In the Midcontinent Independent System Operator (MISO) region, which covers 15 Midwestern and Southern states, necessary transmission upgrades to address long-term issues over the next 20 years are estimated to cost around $40 billion. While this level of spending is essential for maintaining reliability, resilience and access to low cost cleaner resources to consumers over the life of the investments, these plans only cover the northern half of MISO’s footprint. This is due to the fact that MISO is legally constrained by the lack of support from key decision-makers, like public service commissions. The Transmission Owners Agreement, a legally binding document, states at page 228 that “The MISO Plan shall have as one of its goals the satisfaction of all regulatory requirements. That is, MISO shall not require that projects be undertaken where it is expected that the necessary regulatory approvals for construction and cost recovery will not be obtained.” In other words, without state regulatory support, MISO won’t plan in those states. Southern state regulators within MISO’s footprint have consistently opposed long-term regional reliability planning, despite well-documented benefits to consumers. In 2019, regulators from the Louisiana Public Service Commission, the City Council of New Orleans, and the Mississippi Public Service Commission issued a statement dissenting from the majority of MISO state regulators who supported long-term planning. While the City Council of New Orleans has since reversed its stance, other Southern states remain opposed. Both the Mississippi and Louisiana Commissions’ consultants, under the leadership of the commissions that employ them, have challenged the benefits of MISO membership in recent years, despite well documented benefits that come from being part of a regional system that can share resources.  FERC Chair Willie Phillips More Federal Support, More Southern Opposition On May 13, 2024, the Federal Energy Regulatory Commission (FERC) issued Order 1920, a landmark ruling on long-term reliability transmission planning that largely validates MISO’s existing practices. While many supported the ruling, the Mississippi and Louisiana Public Service Commissions strongly opposed it. They challenged FERC’s jurisdiction over transmission planning under the Federal Power Act and questioned the need for long-term reliability planning. After Order 1920 was issued, consultants from Louisiana and Mississippi commissions appealed to FERC for a rehearing of Order 1920 and later sought a review of the decision by the 5th Circuit Court of Appeals. The case will be reviewed in the 4th Circuit, but it’s likely that both commissions will continue to challenge the order. This raises important questions about how state commissions make decisions to challenge federal rules like Order 1920 and the level of public input involved in these decisions. In Louisiana, it’s unclear whether the state’s elected commissioners were even informed when consultants and staff decided to file a joint appeal of Order 1920 with the Mississippi Public Service Commission. Commissioner Davante Lewis, for example, was not notified, as evidenced by his social media posts and a joint Op-Ed supporting Order 1920 published in Utility Dive on July 23. Other Southeastern states have followed suit. The Georgia Public Service Commission passed a resolution opposing Order 1920 in June, followed by an appeal for rehearing to FERC, echoing FERC Commissioner Christie’s dissent, which argued that states lack sufficient input in transmission planning decisions. For Georgia, no public service commissioner has ever attended a SERTP meeting. In MISO south, regulators have largely declined the opportunity to engage in MISO’s stakeholder process, even as MISO and a host of its stakeholders have consistently appealed to them to engage for several years now. Now, Order 1920 specifically requires Transmission Providers like MISO and SERTP utilities to engage directly with states, and to account for their policies in planning. These positions have effectively stalled planning at the boundary between MISO North and South for more than a decade. But state decision-makers still hold the largest balance of power to approve or reject transmission projects in their states. The new Order 1920 does not change this balance of power. It does empower regulators with evidence to make decisions about beneficial investments in grid infrastructure that increase reliability, resilience and affordability. In the current environment, opposition to long-term planning prevents transmission plans from even being developed, much less brought to a vote in state proceedings.  State Public Utility Regulators (from left to right) Sarah Martz (IA), Randal Christmann (ND), Justin Tate (AR), Patrick O'Connell (NM), John Tuma (MN), Commissioner Mark Christie (FERC), Andrew French (KS), and Kristie Fiegen (SD) The Path Forward In a post-Order 1920 world, the State Engagement Period requires regulator engagement over at least six months to discuss or propose a group cost allocation for long-term reliability projects. However, wise state regulators would begin that work now. Furthermore, there’s no rule preventing state regulators in a transmission planning region from meeting to discuss transmission planning or any other multi-state issue. The Organization of MISO States (OMS), Organization of PJM States Inc. (OPSI), and the Southwest Power Pool Regional States Committee (RSC) regularly discuss issues affecting multiple states, from transmission planning and cost allocation to resource adequacy and power market issues. These forums are crucial because state regulators must make vital in-state decisions. Given the interconnected nature of power grids across the country, greater coordination between states is necessary to ensure consumers receive affordable and reliable power. Additionally, increased accountability occurs when regulators are kept informed about initiatives involving transmission planners and system operators. Notably, no current regulator has attended a Southeast Regional Transmission Planning (SERTP) meeting. This needs to change, not just to comply with FERC rules, but because of the many reasons why regulators need to coordinate across state lines. Unprecedented load growth, shifts in power generation resources, and challenges to maintaining reliability demand the attention of state regulators on a regional basis. Success depends on the ability of stakeholders, regulators, and the power industry to work together—and showing up is essential.
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The Southeastern Regional Transmission Planning (SERTP) process encompasses nine utilities across the southeast. SERTP is meant to be a regional process designed to address regional problems “rather than the public utility transmission provider planning only for its own needs or the needs of its native load customers” in line with FERC’s intentions in Order 1000. At this quarter’s SERTP meeting, stakeholders identified numerous problems in process, methodology, and interpretation of the requirements of a regional transmission planning process.
First, 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. Next, stakeholders noted that the winter peak load forecasts appeared to be exceptionally low, given the major announcements from the large utilities in the southeast. While utilities agreed that "there's clearly something wrong" with the materials that were presented to the stakeholders, there is no formal process for stakeholders to follow regarding data errors. Utilities mentioned that stakeholders may be able to gain more information about the data presented through the Critical Energy/Electric Infrastructure Information (CEII) portal. CEII designation is reserved only for trade secrets or other information that may be important to shield from otherwise public view. To gain CEII access, SERTP stakeholders are required to pay hundreds of dollars to Southern Company to conduct a “background investigation”. Utility load forecast data are often already publicly available; however, each utility’s individual forecast may be hidden deep within a state docketed proceeding. Designating otherwise publicly available information as trade secret, confidential, or CEII unnecessarily restricts stakeholder involvement, and regional regulatory oversight. SERTP utilities also agreed with this point at the meeting: not all data deserves to be CEII designated. But there’s no clarity on where the line is between materials that are designated CEII, and public in SERTP. At this point, it is unclear what utility forecasts have been provided to and are being used by the SERTP utilities for modeling purposes. When asked if the recently approved Georgia Power integrated resource plan (IRP), which includes over 6 gigawatts of new load by 2030, was included in the base case data, it sounds like those forecasts may not be included in modeling until next year. Meanwhile, some generation in the Georgia IRP that were approved (and some that were not approved) were included in the SERTP data update. When a utility planning model includes generation that was planned, based on higher load forecasts, but those higher load forecasts were not provided in the same model, the model results will not reflect reality. While some state regulators and utilities have argued that the state IRP process is essentially perfect for transmission planning, IRP incorporation into SERTP is haphazard at best. In another example, Duke Energy’s Carbon Planning efforts are not reflected in the data provided to SERTP. Duke representatives explained that offshore wind projects are not included in the SERTP generation data because those potential projects don’t include a signed generation interconnection agreement (GIA). Meanwhile, Duke has included multiple “proxy” generators at locations where existing coal units are planned for retirement. Those “proxy” generators are not included in Duke’s IRP, nor do those resources have a signed GIA. Meanwhile, offshore wind is in Duke’s state plans, but the SERTP data tell a wholly different story. The North Carolina Utilities Commission public staff noted that the data appears “extremely stale” for regional planning, to which Duke representatives agreed. In perhaps the most bizarre case, Louisville Gas & Electric/Kentucky Utilities (LGEKU) are not even including generation projects that have been approved by their state regulator, the Kentucky Public Service Commission (PSC). Utilities will often conduct an IRP to determine generally the technology types for new power plants, but not necessarily specific locations. Specific generators go through the generator interconnection process to “plug in” to the grid, allowing for a specific location to be studied. State PSCs will often review a utility’s request to either construct, contract with, or acquire a power plant through a proceeding called a Certificate of Public Convenience and Necessity (CPCN). That CPCN approval gives a utility permission to move forward with a new power plant. Still, LGEKU is not including recently approved power plants in the SERTP, because according to LGEKU, those generators also need to have a transmission service request (TSR). If an IRP is sort of like a compass to get you where you’re going, the CPCN is a GPS, and a TSR is the name of your Uber driver on the way to your final destination. Effectively, long-range planning is impossible in SERTP because the TSR is completed so late in the generator development process. LGEKU clarified that the utility theoretically could provide SERTP with updated generation retirement and additions data, because it’s up to each individual utility to determine what the official “cut off” qualifier is for stating intentions, or not. There’s no standard practice. Stakeholders filed requests for evaluation of multiple public policies including the Inflation Reduction Act, resolutions approved by the TVA Board of Director, North Carolina’s carbon law, Georgia’s IRP, and other requests. All of these requests were denied, or otherwise punted to a later date or a separate process. For instance, it was requested that the North Carolina Carbon Plan be included in the SERTP analysis. Duke explained that some transmission projects from its Red Zone Expansion Plan are included in SERTP, but not necessarily the load growth nor the generation, creating a sort of Frankenstein monster of various model inputs that do not all reflect similar forecasts. SERTP has never evaluated a public policy request, and it appears that the utilities involved intend on keeping it that way. FERC’s Order 1920 is designed to improve transmission planning practices and will certainly improve the SERTP process; however, it won’t be able to resolve all problems. For instance, the SERTP process is an annual process, whereas the Order 1920 process is guaranteed to occur at least once every five years. The regulators of the SERTP utilities should be more involved in SERTP and push for improvements in the current annual process, while anticipating the reforms associated with Order 1920. Simon Mahan is the Executive Director of the Southern Renewable Energy Association. |
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