FERC cleared SPP’s tariff—just as PJM’s governance fight turns to who gets to steer the grid. New to this story? Here’s where things stand. FERC’s AD26-7 proceeding has moved PJM governance past generic process complaints. Former FERC Chair Mark Christie urged the commission to pursue fundamental reforms, not limited stakeholder compromises. Board independence, stakeholder authority, and Section 205 filing rights are all in play ahead of the fall fixes FERC requested. That’s the backdrop for the technical-conference comment phase. This is Power Grid Daily. Storm damage, capacity promises, and a queue buckling under speculative load—starting with NIPSCO’s two-week outage. Here's Amanda Durish Cook at RTO Insider:
Indiana Gov. Mike Braun (R) announced that his office is seeking an investigation into Northern Indiana Public Service Co.’s storm readiness and response after a powerful derecho and cluster of tornadoes left residents without power for nearly two weeks and counting. Braun revealed Aug. 24 that he has instructed the Office of Utility Consumer Counselor (OUCC) to file a complaint with the Utility Regulatory Commission, calling for an investigation into NIPSCO’s storm preparedness and response.
Three hundred seventy-four thousand five hundred customers were out at the peak, after 100-to-110-mile-an-hour winds. Restoring damaged 138-kV and 69-kV circuits over two weeks means rebuilding transmission—not just sending more bucket trucks around. Braun has put the right questions in front of the OUCC: ratepayer money, vegetation management, reliability investments, and whether NIPSCO delivered what regulators approved. Crews can perform extraordinarily, and management can still have failed years earlier in the capital plan. And I’d keep the investigation focused on transmission voltage. Look at the damaged steel towers, material supply, foundations, access, and conductor stringing— that timeline shows whether the system was hardened for a 110-mile-an-hour event before Aug. 11. “Largest blackout” describes the outage; it doesn’t excuse it. The IURC needs to trace every approved reliability dollar to an asset condition, a maintenance record, and an outage outcome. This one's from RTO Insider:
FERC has approved an SPP tariff revision to use economic topology reconfigurations as system conditions allow, saying it will help to reduce market production costs and improve the transmission system’s efficiency by relieving congestion and displacing higher-cost generation ( ER26-2592 ). The commission said Aug. 19 that the changes establish a process to ensure that requested configurations are reviewed by SPP and local transmission operators to address potential reliability effects before implementation.
SPP puts this live Oct. 1: instead of paying generators to redispatch around a bottleneck, it can reconfigure the network when conditions allow. It’s cheaper than running a peaker—provided the switching plan survives contact with the actual system. SPP’s market monitor put annual congestion costs above $1.6 billion in 2025. Even a modest reduction matters—but FERC rightly requires SPP and the local transmission owner to review every requested configuration before it goes into service. And review it again when the system changes. A topology that helps during one generator outage can create a nasty contingency exposure when a line trips or wind ramps somewhere else. Operators need authority to unwind it fast; a congestion-savings dashboard won’t do that. MISO reported $95 million saved across 2024 and 2025 under a similar process, and supporters cite $113 million in 2025 congestion savings. Bring that discipline to SPP. Then publish the savings and the reversions, and show who bore the reliability constraints. From RTO Insider:
The term sheet PJM submitted recommended making the stakeholder process advisory and the RTO assuming filing rights over planning and the energy and ancillary service markets under Federal Power Act Section 205. It argued the change would allow PJM to act when the membership is deadlocked.
On PJM governance reform, commenters are pressing FERC for changes to the board and stakeholder process. PJM wants to make the stakeholder process advisory and take Section 205 filing rights over planning, energy, and ancillary-service rules. Which means when the Members Committee deadlocks, PJM can move anyway. That may be necessary in an emergency—but it also shifts a lot of leverage from the people paying the tariff to the operator writing it. PJM also wants to eliminate the Markets and Reliability Committee because proposals can spend a month between MRC and Members Committee votes. Remove a delay, sure. But open Board meetings and nine-year single terms don’t, by themselves, create accountability for an independent filing. The SPP tariff action we just covered shows FERC can approve a discrete market tool when an RTO brings one. PJM is asking for something broader: the authority to decide first, with stakeholders relegated to advice. FERC needs very clear guardrails before signing that over. This one's from RTO Insider:
Ontario’s hourly demand response (HDR) resources delivered only about 64% of their capacity obligations during summer 2025 activations and rarely updated their bids to reflect what they could provide, according to IESO. The shortfall is shaping HDR-related capacity auction changes the ISO proposes for 2027. Only 122 of 1,315 activation hours in summer 2025 (9%) showed a change between day-ahead bids and real-time dispatch hours.
Sixty-four percent delivery against a capacity obligation is a reliability hole, not a rounding error. And 122 bid changes across 1,315 activation hours suggests participants carried day-ahead numbers into real time even when they might not hold. IESO procured these megawatts for reliability, and Bryan Timm makes the key point: a late availability cut leaves the operator no time to buy a substitute. Capacity accreditation has to reflect what shows up when dispatched. Before they redesign a 2027 auction, pull the interruptibility language behind those summer 2025 bids. Were customers firmly obligated to curtail, or could they effectively decide at the last minute? That distinction sits inside the 36% miss. Expanding the capacity test window from one week to a month is sensible—one lucky week can flatter almost any resource. But settlement incentives matter too: if updating availability and underperforming carry similar consequences, the market has designed a very expensive blind spot. RTO Insider writes:
The Bonneville Power Administration could reshape its first-come, first-served transmission queue order and impose stricter requirements to speed up processing of transmission service requests. Several issues have hampered BPA’s commercial transmission planning, including significant increases in requests for long-term firm (LTF) transmission service, unprecedented load growth and disjointed queue processing, according to Chris Gilbert, BPA’s transmission service request study and expansion lead.
BPA’s 64-gigawatt queue has become a reservation system for capacity that may never be built. First-come, first-served works until speculative LTF requests start delaying customers who can actually use the transmission. “Readiness” needs teeth. A polished application doesn’t get you a transformer, a breaker, or a construction slot when the equipment queue is the constraint. Exactly. BPA should tie priority to hard financial milestones and enforceable withdrawal costs, not a project’s ability to fill out forms early. Otherwise, the 64 GW figure stays inflated, and customers paying for upgrades are underwriting somebody else’s option value. Queue order was supposed to be simple. Now BPA has to distinguish real load from a placeholder with a transmission-service request attached. If you’re finding Power Grid Daily useful, please subscribe and leave us a review wherever you’re listening. Reviews help other people find the show, and we appreciate you spending part of your day with us.
Looking ahead: SPP’s economic topology reconfiguration tariff revisions take effect October 1. The next PJM governance checkpoint is FERC’s dispute-mediation process on decision-making, after the technical-conference comments.
Links to every story are in the show notes, so you can dig into the ones you want to explore further. That’s Power Grid Daily for today. This is a Lantern Podcast.