Delaware Gov. John Carney recently signed Senate Joint Resolution 2, which urges FERC to accept either of PJM Interconnection’s alternative cost allocation methodologies for funding the Artificial Island transmission line project as recommended by Carney and Maryland Gov. Larry Hogan, according to a June 29 statement from Carney’s office.
The bipartisan resolution was sponsored by state Sen. Harris McDowell and co-sponsored by state Sen. Cathy Cloutier, as well as state Reps. Trey Paradee and Kevin Hensley, according to the statement.
“We’re hopeful that [FERC] will seriously consider PJM’s proposed alternative financing for the Artificial Island project, and we’re optimistic that would not unjustly burden electric ratepayers on Delmarva,” Carney said in the statement. “As we’ve said before, Delawareans and Delaware businesses should not be forced to finance this project through higher monthly electric bills, while receiving little in the way of a direct benefit.”
McDowell said in the statement, in part: “What [PJM has] returned with is a pair of win-win-win alternatives that achieve stability in the region’s power grid at a fair cost to Delaware and its residents. I’m grateful for their willingness to hear us out and to work with us; now it’s incumbent upon the FERC to honor these fair-minded compromises and protect consumers across the region by accepting one of these alternatives.”
When reached by TransmissionHub on July 7 about the Delaware resolution, FERC did not have a comment.
Denise Foster, vice president of State and Member Services with PJM, said in a statement provided to TransmissionHub on July 7: “PJM appreciates the recognition from officials in Delaware in their resolution regarding the analysis PJM performed on alternative methodologies to allocate cost for Artificial Island. PJM is aware that stakeholders in Delaware and Maryland likely will apply the analysis to a pending appeal with” FERC.
According to PJM, the Artificial Island was approved by the PJM Board of Managers and pending other licensing and permitting, it is expected to be completed by June 2020.
As TransmissionHub reported, PJM on April 6 said that its board has approved lifting the suspension on the Artificial Island project, which PJM said will strengthen the reliability and transmission of high-voltage power from two nuclear generating stations in southern New Jersey.
The board initially approved the project in 2015 as a result of a competitive solicitation process, and called for construction of a 230-kV transmission line under the Delaware River, PJM said. The board designated LS Power to build the line, as well as Public Service Enterprise Group’s (NYSE:PEG) (PSEG) Public Service Electric & Gas and Delmarva Power, an Exelon (NYSE:EXC) company, for other portions of the project, including electric substation work, PJM said.
The board last August suspended the project, and directed PJM to perform a comprehensive analysis to support a future course of action, PJM said.
PJM noted that it reviewed its analysis with a stakeholder advisory committee.
The board reinforced support for building the 230-kV line from the area where the Salem and Hope Creek nuclear facilities operate to a new substation to be built in northern Delaware, PJM said.
Among the modifications to the original solution, the line will now be connected at the Hope Creek substation instead of the Salem substation, PJM said, noting that the project is expected to cost about $280m.
In a June 9 document, “Alternative approaches to identification of Artificial Island project beneficiaries,” PJM noted that the board also directed PJM to provide information to states and stakeholders that they could consider in addressing issues concerning cost allocation of the project.
Specifically, PJM noted, since cost allocation disputes often center on identification of the beneficiaries of a given project, the board asked PJM staff to outline potential means to identify beneficiaries of projects performed for stability reasons that could be considered in addition to the strict application of the solution-based distribution factor method, or DFAX.
As noted in the document, the DFAX methodology includes such analysis components as zonal netting and nesting, the treatment of phase angle regulators, and a threshold for projects included in the Regional Transmission Expansion Plan (RTEP).
PJM said that the board’s call for exploring alternatives was in response to concerns expressed by legislators, consumer advocates, and other stakeholders regarding cost allocation of the $280m project and in recognition that, unlike most thermal-driven projects, there are a number of different ways to identify the beneficiaries of a stability based project like Artificial Island.
PJM noted that FERC Order 1000 required that regional cost allocation methods for new or upgraded transmission facilities included in an RTEP be allocated in a manner that is “roughly commensurate” with the benefits received by those who will pay the costs.
Following issuance of Order 1000, the FERC-accepted regional cost allocation methodology for RTEP projects needed to address reliability issues was a flow-based methodology that identified the load zones that contributed to the loading on the new or upgraded facility, PJM said.
While the flow-based approach works fairly and reasonably to identify project beneficiaries in the vast majority of projects involving thermal and voltage reliability criteria, in some instances where a particular project is not needed to address thermal or voltage reliability criteria, the results of the cost allocation methodology may produce a perceived gap between the allocation of costs and the benefits, PJM said.
For instance, the cost allocations for the Artificial Island project, which is being driven by a stability issue, may raise issues as to whether the costs of the project are fairly allocated to all of the appropriate beneficiaries of the project, PJM said. As applied to the Artificial Island project, 93% of the cost is allocated to the Delmarva Power region, PJM said, adding that the “project is the largest scope generator stability driven project since the 2000 inception of PJM’s [RTEP]; therefore, there is no precedent for using a different method to identify and measure beneficiaries.”
PJM said that in order to explore the potential for alternative cost allocation methods for stability driven projects, PJM planners considered a broad range of approaches to measuring the beneficiaries of stability solutions, and of those studied, two alternative cost allocation methods emerged that may be reasonable to apply to upgrades that address stability: a stability interface DFAX approach and a stability deviation approach.
Discussing the stability interface DFAX method, PJM noted that the stability of a generator, or a collection of generators in an area of the system, is dependent on the robustness of the transmission that connects the generator(s) to the rest of the system. The stability interface DFAX method establishes a closed interface that surrounds the generator(s) with the stability issues, PJM said, noting that the interface is the collection of lines that connect generators to the rest of the system.
The stability interface DFAX method determines the DFAX for each transmission facility that comprises the interface in the same manner as the existing solution-based DFAX cost allocation methodology, PJM said.
The solution-based DFAX calculation quantifies the percent usage of flow on a facility by each load zone, and that percentage is then used to formulate a cost allocation to each load zone, PJM said. Under the solution-based DFAX, the calculation of the DFAX for each transmission zone and merchant transmission facility with firm transmission withdrawal rights is based on its use of the upgrade to deliver PJM generation to serve its load. PJM added that it uses the annual RTEP starting base case to develop all DFAX values for new RTEP enhancements or expansions. A DFAX represents a measure of the use of the upgrade by each megawatt of a zone’s load served by a megawatt of PJM generation, as determined by power flow analysis, PJM said.
Under the stability interface DFAX, DFAX values that are not in the same direction as the predominant hourly usage are ignored, PJM said, adding that the DFAX for each zone is multiplied by the peak load of the zone. For each zone, the megawatt impacts on each facility making up the interface are added together, PJM said, noting that those megawatt impacts for each zone form the basis for the allocation.
Using the stability interface approach to identifying beneficiaries, geographically, the cost allocations for the Artificial Island project are, for instance: PSEG – 42.06%; PECO – 19.94%; JCPL – 13%; AEC – 7.31%; and DPL – 6.94%.
The stability deviation method identifies beneficiaries of projects by identifying loads that are impacted by critical faults that are evaluated to assess the stability performance of a generator or cluster of generators, PJM added.
The critical faults or disturbances, such as the failure of a transmission line or piece of substation equipment, that are typically evaluated to assess the stability of a generator, may involve more severe disturbances that are removed very quickly or less severe disturbances that take longer to be removed, both of which are evaluated under maintenance conditions, PJM said.
Power system engineers often describe the voltages at a given substation as a magnitude and an associated angle with respect to the common reference, PJM said, noting that the change in the angle of the voltage is higher for substations that are more impacted by the disturbance or stability event. The stability deviation method uses that angle change as a basis to identify those most impacted by the disturbance as the beneficiaries of the stability project, PJM said.
The first step with that method is to perform a transient stability study for the worst-fault conditions and monitor the angle deviation at each PJM substation, PJM said, noting that mathematically, every location on the electric grid will experience some measureable angular deviation, even if very small.
Substations with angle deviations of less than 25% of the largest angle deviation would be ignored, PJM said. The angle deviation at each substation is multiplied by the load at the substation and summed with all of the other substations in a transmission zone, and that establishes a load-weighted angle deviation for each transmission zone, PJM said.
Among other things, PJM said that the total load-weighted angle deviations for each transmission zone would then represent the aggregate impact of the disturbance on the customer load in the zone and form the basis for the allocation.
Using the stability deviation approach to identifying beneficiaries, geographically, the cost allocations for the Artificial Island project are, for instance: PSEG – 18.86%; PECO – 15.17%; PPL – 12.53%; JCPL – 12.38%; DPL – 10.36%; and AEC – 7.24%.