The following describes the different types of reliability projects and their cost allocation approach in PJM:
RTEP (Regional Transmission Expansion Plan) Reliability Projects Description and Cost Allocation[1] (Reliability Projects are Required Transmission Enhancements that are included in the RTEP to address one or more reliability violations or to address operational adequacy and performance issues) 1. Regional Facilities Required Transmission Enhancements included in the RTEP that are transmission facilities that: (a) are AC facilities that operate at or above 500 kV; (b) are double-circuit AC facilities that operate at or above 345 kV; (c) are AC or DC shunt reactive resources connected to a facility from (a) or (b); or (d) are DC facilities that meet the necessary PJM. Costs allocated using a hybrid cost allocation method – 50% allocated on a load-ratio share basis and 50% allocated using solution-based distribution factor (DFAX) method[2] 2. Necessary Lower Voltage Facilities Required Transmission Enhancements included in the RTEP that are lower voltage facilities that must be constructed or reinforced to support new Regional Facilities. Costs allocated using a hybrid cost allocation method – 50% allocated on a load-ratio share basis and 50% allocated using solution-based distribution factor (DFAX) method 3. Lower Voltage Facilities Required Transmission Enhancements that: (a) are not Regional Facilities; and (b) are not “Necessary Lower Voltage Facilities. 100% allocated using solution-based DFAX method 4. Local Planning (Form 715) Facilities Projects resulting from Annual Transmission Planning and Evaluation Report that any transmitting utility that operates integrated transmission facilities at or above 100 kV must file with the Commission. Form No. 715 requires submission of transmission planning reliability criteria that the transmission owner uses to assess and test the strength and limits of its transmission system. Allocated as Regional Facilities, Necessary Lower Voltage Facilities or Lower Voltage Facilities, depending into which category the Local Planning Facility fits.[3] In developing the RTEP, PJM identifies transmission projects to address different criteria, including PJM planning procedures, North American Electric Reliability Corporation (NERC) Reliability Standards, Regional Entity reliability principles and standards, and individual transmission owner Form No. 715 local planning criteria. [1] Per Schedule 12 of the PJM OATT [2] The Solution-Based DFAX method evaluates the projected relative use on the new Reliability Project by the load in each zone and withdrawals by merchant transmission facilities, and through this power flow analysis, identifies projected benefits for individual entities in relation to power flows. [3] Compliance filing pending at FERC in Docket No. ER15-1344.
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In January 23, 200 in ER15-1436, FERC determined that Entergy’s proposal to include prepaid and accrued pension costs in its transmission formula rate has not been shown to be just and reasonable. FERC’s finding is without prejudice to Entergy making a future filing that adequately demonstrates that its future proposal, including its methodology for calculating prepaid and accrued pension costs, is just and reasonable.
First, FERC described pension accounting and when it is appropriate to include prepaid pension costs or accrued pension costs in rate base. Prepaid and accrued pension costs can arise when a utility makes contributions to fund a pension trust in order to meet employee pension plan obligations. The costs associated with the pension plans that are reported on the utility’s income statement are referred to as the utility’s “pension expense” or “net periodic pension cost.” Pension expense for a given year includes pension obligations accrued that year, interest, and the return on the assets in the trust (specifically, the components of pension expense are service cost, interest cost, actual return on plan assets, gain or loss, amortization of unrecognized prior service cost, and amortization of the unrecognized net obligation of asset). While pension obligations and interest increase pension expense, the return on the assets in the trust will generally decrease pension expense. A utility generally receives recovery of pension costs based on the amount of pension expense recorded on the books. Accordingly, a prepaid pension cost (an asset) is the amount by which cumulative contributions to a pension trust exceed cumulative pension expense. An accrued pension cost (a liability) is the amount by which cumulative pension expense exceeds cumulative contributions. As a general matter, it is just and reasonable for a utility to include prepaid pension costs in rate base when its pension expense recovered from customers is less than its contributions to fund pension costs (increase to rate base). Likewise, it is just and reasonable for a utility to include accrued pension costs in rate base when it has recovered pension expense from customers in excess of its pension costs (reduction to rate base). Entergy states that its independent actuary calculates prepaid pension costs by taking the pension plan’s Funded Status (which is Fair Value of Plan Assets minus Projected Benefit Obligation) for the year and then backing out Unrecognized Gains/Losses. This can be reflected in the following formula: Prepaid or (Accrued) Pension Cost = Fair Value of Plan Assets – Projected Benefit Obligation + Unrecognized Net (Gain) or Loss FERC found that Entergy had not demonstrated that its proposed formula for calculating prepaid pension costs is just and reasonable. Consistent with the above explanation, the appropriate way to calculate prepaid pension costs includable in rate base would be to calculate the cumulative differences between each year’s pension contributions made by Entergy and pension expenses. Entergy proposes to use a different formula (i.e., Funded Status minus Unrecognized Gains and Losses). Although Entergy asserts that this formula leads to the same result, we find that Entergy has not adequately supported this claim. Specifically, Entergy’s proposed formula includes components that Entergy has not fully explained and that may not be appropriate to include in the calculation of prepaid pension costs to be included in rate base. For instance, although Entergy argues that it is reasonable to calculate prepaid pension costs by starting with the plan’s Funded Status and backing out Unrecognized Gains/Losses, Entergy does not adequately explain what comprises Unrecognized Gains/Losses or why backing out those amounts to compute prepaid pension costs in rate base yields a just and reasonable result. Without additional explanation, we are unable to evaluate whether Unrecognized Gains/Losses are an appropriate component to include in the calculation of prepaid pension costs to be included in rate base. Furthermore, Entergy did not explain why using the Funded Status is an appropriate methodology to calculate prepaid pension costs in rate base. Entergy explains that Funded Status equals Fair Value of Plan Assets minus Projected Benefit Obligation, but Entergy does not explain why using Funded Status and Unrecognized Gains/Losses yields the same result as calculating cumulative employer contributions and cumulative pension expense. In some instances, it may be inappropriate to use Funded Status for calculating prepaid pension costs. For example, Entergy’s actuarial disclosure includes a line item for employee contributions for the calculation of Fair Value of Plan Assets, which is a component of Funded Status. However, employee contributions to a pension trust are not shareholder financed funds that the utility has paid out of pocket. Consequently, it would not be just and reasonable for Entergy to include amounts that employees contribute to pension plans in rate base and earn a return on such amounts. Lastly, FERC found that Entergy’s pension plan funding discretion did not, in and of itself, make Entergy’s proposal unjust and unreasonable. Entergy states that it aims to fully fund its pension plans at the 100 percent level and to not let the funding levels fall below 80 percent. Entergy is not required to provide a policy statement or other documents describing how it exercises its pension funding discretion. As discussed above, while we are rejecting Entergy’s proposal to include a line item for prepaid and accrued pension costs in rate base, we note that, to the extent a utility has a line item for prepaid or accrued pension costs in its transmission formula rate and customers are concerned the utility has funded its pension plans at levels that are not prudent, they may challenge the utility’s pension funding levels when the utility files its annual transmission formula rate updates. FERC recently issued Opinion 554-A related to the Path (Potomac-Appalachian Transmission Highline, LLC) transmission project, which was cancelled by PJM in 2011. The PATH Project was to be a 275-mile 765 kV line from Amos Substation in West Virginia through Virginia to a new Kemptown Substation in Maryland. In Opinion 554, FERC had found that PATH’s base ROE should be reduced from 10.4% to 8.11% to reflect reduced risks (FERC found that, in the abandonment phase of the PATH Project, PATH's risk profile had decreased significantly as compared to the proxy group companies that face ongoing business risks). Additionally, FERC disallowed certain civic, political and related costs from recovery. PATH requested rehearing of Opinion 554. FERC granted rehearing for the following items:
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Dr. Paul DumaisCEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates, reactive power and more. Archives
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