PJM Interconnection CEO and President Andrew Ott, in a letter to stakeholders and government officials in Delaware and New Jersey, said that “PJM has suggested that the Artificial Island project is unique in nature and that application of the [current distribution factor method, or] DFAX methodology to a stability or short-circuit problem may not yield clear beneficiaries.”
PJM’s June 9 document, “Alternative approaches to identification of Artificial Island project beneficiaries,” added that Ott said in his letter that while a solution-based power flow formula – the current DFAX – works fairly and reasonably to identify project beneficiaries for most lower-voltage transmission projects, it can result in anomalous results in cases where the engineering rationale or need for the particular project is not driven by power flows.
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).
As TransmissionHub reported, PJM on April 6 said that its Board of Managers 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, and to be in service June 2020.
In its June 9 document, 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 solution-based DFAX.
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.”
Two methods emerge
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.
While the Artificial Island project was used as the test case for developing the alternative approaches, the methodologies would be applicable to any project that is addressing a stability issue for a generator on the system or clusters of generation in an area of the system, PJM said.
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%.
In a June 9 post on its Inside Lines website, PJM said that it is not taking a position on the alternatives discussed in the analysis, which is intended to provide transmission owners, the states, and other stakeholders alternatives to the existing cost allocation methodology that might better align with stability projects.
PJM said that while it would participate in, and support further discussion of the issues in any proceedings that FERC might initiate, PJM does not intend to file its analysis or an alternative cost allocation with FERC, which would determine how to proceed, should there be further discussion on the Artificial Island issues.
Delaware PSC responds
As noted in a June 9 statement, the Delaware Public Service Commission (PSC) in August 2015 filed a complaint with FERC alleging that use of the solution-based DFAX cost allocation methodology as applied to the Artificial Island project was unjust and unreasonable. That complaint was denied in April 2016, the PSC said, adding that it is seeking reconsideration of FERC’s denial, and that the newly provided analysis supports Delaware’s petition for reconsideration.
The PSC said that it and others are evaluating PJM’s alternative analyses and will consider further regulatory or legal actions as may be needed to help secure an improved cost allocation approach for Delaware ratepayers.