I've been finding significant transmission cost allocation errors in Alabama Power's deregulated industrial accounts. While most of Alabama is still regulated, certain large industrial customers have competitive supply options, and the transmission cost unbundling has been problematic. One client was being charged $12,000/month for Network Integration Transmission Service that should have been $7,200 based on their actual load ratio share. The utility was using outdated coincident peak data from 2019 instead of current measurements. Has anyone else seen systematic errors in transmission cost allocation when accounts move between regulated and competitive supply?
Transmission cost allocation errors in deregulated territories
Zach, I've encountered similar issues in Ohio with FirstEnergy's transmission cost allocation. The problem often occurs during the transition period when accounts switch from regulated to competitive supply. The billing systems sometimes retain old transmission cost assignments that aren't updated to reflect current usage patterns. In one case, I found a manufacturing facility being charged transmission costs for a 5MW load when their actual peak was only 3.2MW. The error persisted for 14 months before we caught it, resulting in $84,000 in overcharges.
Arizona is mostly regulated, but we have some wholesale transmission customers that face similar allocation issues. The key is understanding how the transmission provider calculates the Network Service Peak Load and Transmission Peak Load allocations. These should be based on the customer's contribution to the transmission system peak, but I've seen cases where utilities use incorrect measurement periods or fail to update for load changes. The OATT requires specific methodologies that utilities sometimes ignore or misapply.
In New York, the NYISO transmission cost allocation is supposed to be transparent, but I've found numerous errors in how load-serving entities allocate costs to their customers. The Monthly ICAP charges are particularly problematic - suppliers often use stale data or incorrect zone assignments. One issue I see frequently is suppliers failing to update transmission cost allocations when customers install on-site generation or implement demand response measures that reduce their transmission system impact.
Michigan's transmission cost allocation under MISO has its own complexities. DTE and Consumers Energy sometimes use different methodologies for allocating regional transmission costs versus local transmission costs. I've found errors where customers are double-charged for certain transmission upgrades - once through the regional cost allocation and again through local rates. The Planning Resource Auction charges are another area where I frequently find allocation mistakes, especially for customers with complex load profiles or multiple service points.
Pennsylvania has some unique transmission cost issues because of the PJM footprint overlapping with state jurisdiction. I've seen cases where customers switching to competitive supply suddenly face different transmission cost allocation methodologies than they had under regulated service. PPL and PECO sometimes calculate Network Integration Transmission Service charges differently, leading to bill impacts that weren't properly disclosed during the competitive supply enrollment process. The transmission cost reconciliation process is also poorly understood by most suppliers.
ComEd territory has ongoing transmission allocation issues related to the Multi-Value Project charges in MISO. Customers often don't understand that competitive suppliers may allocate these costs differently than ComEd did under regulated service. I've found significant discrepancies in how suppliers calculate and pass through the MVP charges, especially for customers with seasonal load patterns. The Transmission Cost Recovery charges are another area where suppliers frequently make errors, particularly in determining the appropriate cost allocation factors.
Texas ERCOT transmission cost allocation is supposed to be straightforward with the zonal methodology, but I've still found numerous errors. The biggest issue is suppliers incorrectly allocating transmission congestion revenue rights and transmission cost recovery factors. Some suppliers use outdated zone definitions or fail to properly adjust for load migrations between zones. The seasonal variations in transmission cost allocation are also frequently mishandled, leading to significant billing errors during peak summer months.
While Idaho doesn't have retail choice, I work with some large customers who participate in wholesale markets through Idaho Power. The transmission cost issues you're all describing highlight why proper market design is so important before opening retail markets. The complexity of transmission cost allocation creates numerous opportunities for errors and disputes. It seems like the billing systems and staff training often lag behind the market structure changes, leading to systematic problems that can persist for years.
Arkansas is still regulated, but I monitor deregulated market issues for potential policy impacts. What strikes me about these transmission cost allocation problems is how they disproportionately affect large industrial customers who often lack the resources to audit complex transmission charges. Small commercial customers usually have transmission costs bundled into simple rates, but large customers face sophisticated cost allocation methodologies that require expert analysis to verify. This creates a significant information asymmetry in competitive markets.
Georgia Power territory has limited competitive options, but I've worked on wholesale transmission cost disputes that involve similar allocation methodologies. The fundamental issue is that transmission systems were designed and built under regulated utility models, but now they're being used to support competitive retail markets with different cost allocation requirements. The technical complexity of power flow calculations and cost causation principles makes it difficult for customers to verify that they're being charged appropriately for their actual transmission system usage.
Oregon doesn't have retail competition, but PacifiCorp operates across multiple states with different market structures. I've seen how transmission cost allocation can become problematic when utilities serve both regulated and competitive markets. The challenge is maintaining consistent and transparent methodologies across different regulatory jurisdictions while ensuring that customers pay their fair share of transmission system costs. The errors you're all finding suggest that many utilities and suppliers haven't adequately invested in the systems and training needed to handle these complex allocations accurately.
The transmission cost allocation issues are getting worse as more states consider market restructuring. I've been following developments in several states where regulators are proposing competitive markets without fully understanding the transmission cost complications. Customers need to understand that switching to competitive supply often means taking on transmission cost risks that were previously managed by regulated utilities. The billing complexity alone requires professional auditing to ensure accuracy.
This discussion really highlights the importance of transmission cost auditing in deregulated markets. I've been working with MLGW on some industrial accounts that are considering competitive supply options, and the transmission cost allocation methodology is one of the biggest concerns. Customers often focus on the generation supply rates but don't realize that transmission cost changes can have much larger bill impacts. The lack of standardization across different ISOs and RTOs makes it even more challenging for customers operating in multiple states to manage these risks effectively.