The Federal Energy Regulatory Commission (“FERC”) recently issued an Advance Notice of Proposed Rulemaking (“ANOPR”) on transmission planning and cost allocation (FERC Docket No. RM21-17-000). FERC’s ANOPR seeks comments on a wide range of complex issues, including whether utilities need to revise their planning processes to consider longer time frames, whether generation owners should fund transmission upgrades to make their generation fully deliverable to the transmission grid, and whether a portfolio of projects should be considered in the allocation process as opposed to individual projects. Comments on these issues may result in better methodologies for determining which transmission users should pay for system upgrades and how much they should pay.
This ANOPR is well-timed given the likely changes in the transmission fleet, with wind and solar energy replacing coal-fired generation, and the current litigation on transmission cost allocation. For example, fifteen FERC orders concerning the PJM Interconnection L.L.C. (“PJM”) transmission cost allocation are on appeal to the federal courts. Additionally, FERC is processing two complaints concerning the PJM cost allocation methodology. A review of the current PJM litigation on transmission cost allocation highlights the complexity of the issues facing all FERC-jurisdictional service areas.
Most transmission payments to PJM cover the cost of the individual utility transmission system in which the load (demand) is located. For example, load in Baltimore, Maryland pays for most of the transmission costs of the Baltimore Gas & Electric transmission system. However, new transmission facilities costs that are considered to produce regional benefits, such as upgrades to the high-voltage 500 kV transmission system, are allocated to all ratepayers in PJM. For example, fifty percent of the regional upgrade costs on high-voltage components (230 kV and above) are allocated based on shares of peak load. The remaining fifty percent of the upgrade costs are allocated by estimating the benefits of the upgrade using a methodology based on energy flows. This methodology is known as a Flow-Based Method, or alternatively as a Distribution Factor Method, or DFAX Method. Distribution factors measure the share of energy that flows through the transmission facilities going from generation sources to loads. For lower-voltage upgrades, costs of “regional” upgrades are allocated using only the Flow-Based Method. In contrast, when an upgrade is not considered regional, the costs are borne solely by the ratepayers of the utility implementing the upgrade.
Several assumptions are necessary to implement a Flow-Based Method, and FERC is reviewing complaints concerning two assumptions in PJM’s methodology. The first assumption under review is the distribution factor cut-off. The intuition behind the distribution-factor cut-off is that systems that are distant do not benefit from, and thus should not have to pay for, transmission upgrades far away. For example, transmission ratepayers in Chicago should not have to pay for transmission upgrades in New Jersey, and vice versa. Power flowing between any two points on a transmission system induces at least some power flows on every transmission line on the system. Without a cut-off, ratepayers in Chicago would pay a share of the costs for regional transmission upgrades in New Jersey. PJM currently sets its cut-off at one percent. This may seem low, because cut-offs of three percent or higher often are used for calculating transmission availability and for market power mitigation protocols. But setting the distribution cut-off too high, even at one percent, can result in the cost being allocated to a very small share of ratepayers—which means these ratepayers may pay very high rates for a project that has regional benefits. At present, there is no research-supported reason for the cut-off being set at any specific level, nor has research been presented on the net effects on sets of ratepayers from using different cut-off values. Hence, those viewing themselves as disadvantaged by the cut-off being set at one percent argue that the cut-off should be set at a lower level in order to allocate costs to a broader group of ratepayers.
The second assumption under review is called netting. To understand netting, consider the following example. Utility A has a north zone and a south zone, with energy generally flowing from north to south. Further suppose that Utility B has load embedded in the south zone. Finally, suppose that Utility A’s load grows in the south, and to serve this growth Utility A needs a transmission upgrade. At the same time, Utility B’s load in the south zone remains constant. With netting, the energy flows to serve Utility A’s north load are netted against Utility A’s south load. If Utility A’s loads in the north zone and south zone are roughly equal or if the north load is greater than the south load, then Utility A may not be allocated any of the costs associated with its transmission upgrade. Whereas, Utility B may be allocated one hundred percent of the costs, even though Utility B’s load did not change and Utility B does not need the upgrade.
In this environment, FERC’s ANOPR seeks comments on a wide range of issues. In Order No. 1000, FERC stated that the first principle for transmission pricing is that cost allocation be roughly commensurate with the benefits received by those who pay. The problem is properly identifying the benefits received by ratepayers, of which the PJM methodology is one of many possible solutions. Comments to FERC may help identify a methodology that yields better information on who benefits from changes to the transmission system, and thus may result in better methodologies for determining which transmission customers should pay, and how much they should pay, for system upgrades.