Heads up everyone - FERC issued Order 1000-B last week that significantly changes how transmission costs are allocated in all RTO/ISO markets. The new ruling requires regional transmission organizations to allocate costs for reliability projects above $50 million based on load ratio share rather than the previous beneficiary-pays model. This is going to impact billing in PJM, ERCOT, CAISO, ISO-NE, NYISO, and other deregulated markets starting January 2024. Commercial and industrial customers should expect transmission charge increases of 8-15% in most regions. I'm putting together a client advisory - anyone else tracking this development?
PSA: New FERC ruling on transmission cost allocation - impacts all deregulated markets
Randy, thanks for the heads up. I'm already seeing questions from Texas clients about transmission cost projections for 2024 budgets. The load ratio share methodology is going to be particularly painful for large industrial customers who previously benefited from the beneficiary-pays model. A steel mill client in Houston is projecting an additional $180,000 annually in transmission charges under the new allocation. Are there any exemptions or phase-in periods for existing projects already under construction?
This is going to be huge for California clients. CAISO has about $2.8 billion in approved transmission projects that will now be allocated differently. Industrial customers in Northern California who weren't direct beneficiaries of Southern California transmission upgrades are going to see significant cost increases. The order does include a three-year phase-in for projects already approved, but new projects starting after January 1, 2024 will use the full load ratio share immediately. Anyone know how this interacts with state renewable energy mandates that drive transmission investment?
Jennifer, great question about renewable energy mandates. In PJM territory we're seeing massive transmission investment driven by offshore wind interconnections, and under the new FERC ruling those costs will be spread across all load rather than just the coastal areas that benefit from the wind power. Pennsylvania manufacturing clients are going to subsidize New Jersey's offshore wind transmission infrastructure. This seems to conflict with state energy policies that assume beneficiaries will pay for renewable infrastructure costs.
I'm concerned about how this impacts customer choice decisions in deregulated markets. If transmission costs become more socialized and less predictable, it reduces the value proposition of retail choice since customers have less control over their total electricity costs. Large customers who could previously negotiate around transmission costs through siting decisions or direct utility arrangements now face higher unavoidable charges. This could drive more customers toward on-site generation or storage solutions to reduce transmission exposure.
David raises an important point about customer behavior changes. We're already seeing large industrial customers in Texas and PJM exploring behind-the-meter solutions to reduce transmission charges. The unintended consequence of FERC's ruling might be accelerated grid defection by the customers who can best afford distributed generation. This could create a death spiral where remaining customers bear even higher transmission costs as the load base shrinks. State regulators need to be thinking about this dynamic in their long-term planning.
From an auditing perspective, this is going to make transmission cost forecasting much more complex. Previously we could analyze specific transmission projects and their likely beneficiaries to predict cost allocation. Now we need to track all regional transmission investment and model load ratio share impacts across entire RTO footprints. I'm already updating my audit software to handle the new allocation methodologies. Anyone found good data sources for tracking regional transmission project pipelines?
Connie, I've been using SNL Energy and S&P Global Market Intelligence for transmission project tracking, but their data is expensive and not always current. FERC's eLibrary has the official filings but they're hard to aggregate and analyze. Each RTO publishes regional transmission plans but the formats are inconsistent and the cost allocation details are often incomplete. We really need a centralized database that tracks approved projects, estimated costs, and allocation methodologies across all regions.
Marcus, have you looked at the North American Transmission Forum (NATF) database? They've been working on a comprehensive transmission project tracking system that includes cost allocation data. It's primarily for utilities and transmission developers, but they have a consultant access program that might work for our needs. The annual subscription is around $15,000 but it could be worth it for auditors who work across multiple RTO regions. I'm considering a group subscription if there's enough interest.
This whole discussion highlights why I prefer working in traditional regulated markets. FirstEnergy may not be perfect, but at least their transmission cost recovery is transparent and predictable through the rate case process. Deregulated markets promised efficiency and innovation, but we're getting complexity and cost shifting instead. Large customers are sophisticated enough to navigate these changes, but small commercial customers are going to get blindsided by transmission cost increases they can't understand or control.
Frank, I understand your frustration with market complexity, but the alternative is worse. In regulated markets, customers have no choice when utilities gold-plate transmission infrastructure or make poor investment decisions. At least in deregulated markets, customers can respond to price signals through demand management, distributed generation, or load shifting. The FERC ruling isn't perfect, but it's trying to address free-rider problems where some customers benefit from transmission investments without paying their fair share.
I'm caught between regulated Georgia Power territory and deregulated markets in other states where I have clients. Both systems have problems, but at least regulated utilities have predictable cost recovery mechanisms that make budgeting easier. The real issue with this FERC ruling is the timing - it's being implemented during a period of massive transmission investment driven by renewable energy integration and grid modernization. Customers are going to see huge rate increases right when they're dealing with inflation and supply chain issues.
Eleanor makes a good point about timing. The combination of FERC Order 1000-B, state renewable portfolio standards, and federal infrastructure investment is creating a perfect storm of transmission cost increases. As auditors, our job is to help clients understand these cost drivers and develop strategies to manage them. Whether it's load factor improvement, demand response participation, or distributed generation investment, there are tools available to mitigate transmission cost exposure. We just need to get better at explaining the options to our clients.
Randy, you're absolutely right about our role as advisors. I'm already working with Wisconsin manufacturing clients who have operations in multiple states to develop transmission cost hedging strategies. It's becoming as important as generation price hedging for large multi-site customers. The key is understanding each RTO's specific allocation methodology and helping clients optimize their load profiles accordingly. This FERC ruling is going to keep us all busy for the next few years!