Nonbypassable Charges, 36-Month Laddering Highlight Dayton Power & Light Default Service Plan

Dayton Power & Light's electric security plan includes laddered 36-month contracts for the auction-sourced portion of default supply, and the potential inclusion of generation costs in a nonbypassable rider.

As first reported by Matters yesterday, DP&L's proposal contemplates a gradual blending of its current electric security plan pricing with an increasing amount of auction-sourced default service supplies (see prior story for blending schedule).

DP&L's filed application provides more specifics on the auction to be used for a portion of, and eventually all, default service supply.

The auction will be a descending clock auction for load following, full requirements service, on a slice-of-system basis. The auction product will include energy, capacity, market-based transmission charges, and ancillary services, but will exclude alternative energy compliance requirements, which will be met by DP&L, rather than SSO suppliers, for all SSO load.

A laddering process for auction-sourced SSO supplies would be established relying heavily on 36 and 24 month contracts (with an initial 12-month contract to start the laddering).

The precise laddering and SSO contract terms lengths may be found here.

An 80% load cap would apply in the auctions.

During the blending process, the full requirements auction price from the competitive bid process (CBP) would be blended with tariffed charges for base generation, fuel, capacity, and bypassable transmission costs.

DP&L intends to maintain its demand and energy rate structure to the extent possible yet blend in market-based results of the competitive bid (CB).

The auction price will be stated on a $/MWh basis and will include unbundled energy, capacity, market-based transmission and ancillary services from PJM, transmission and distribution losses, congestion, and imbalance costs. DP&L will adjust that price for distribution losses, commercial activities tax (CAT), and uncollectible expense, and then convert the rate into demand and energy components

The rates will be stated on $/kWh or $/kW on a standalone CB tariff, and applied on a per kWh and/or kW basis to SSO customers based on tariff class.

DP&L will assign the costs associated with the CBP to tariff classes using a blend of two methodologies.

The first methodology assigns the CBP results to tariff classes and to demand and energy components based on today's base generation rate structure. DP&L's current base generation rate structure, at the blend percent for that period, is applied to forecasted SSO load by tariff class. This methodology maintains the demand, energy and blocking (e.g., 0-750 kWh, over 750 kWh) relationships within tariff classes that exist today. The resulting revenue is compared to the expected CBP costs (blend percent x auction results x forecasted SSO kWh, adjusted for distribution losses, CAT and bad debt). A ratio is calculated on the difference between the CBP costs and the expected revenues based on DP&L's current base generation revenue and SSO load. This ratio is then applied to DP&L's base generation rates to develop new CB rates to recover the CBP cost.

The second methodology is based on the proxy RPM price that is in place during the period. CBP costs are first assigned to demand using the published RPM price in effect at that time, all other costs being assigned to energy. This RPM methodology, given today's market prices, would assign most of the costs to an energy-based rate.

In order to provide a mix of today's prices with market prices, DP&L plans to calculate the CB Rate based on a blend of the above two methodologies. For the first period, 90% of the rate resulting from the current rate methodology will be blended with 10% of the rate resulting from the RPM methodology. For the second period, the CB rate will be a blend of 60% current rate structure and 40% RPM structure. This blend will be consistent with the ESP/CBP blend percentages until June 2016 when the CB rate will reflect 100% of RPM methodology. This sequence will allow for the CB rate gradually to reflect actual wholesale prices.

The resulting CB rate will be applied to all SSO load by tariff class, based on energy and/or demand (depending on tariff class). Tariff classes that currently have demand based components will continue to have demand based components. Tariff classes that do not currently have demand based components will continue to have all energy based rates.

The CB Rate will be trued-up on seasonal quarters and will be bypassable.

DP&L's tariffs currently contain a maximum charge provision such that the maximum rate (stated on an energy-basis) does not exceed a certain level. Since the time that electric rates were unbundled in 2001, this maximum charge provision has been modified several times, but has been confusing to customers and retail providers. DP&L intends to phase-out its maximum charge provision over the blending period.

During the blending period, bypassable components will include base generation, fuel, capacity (RPM rider), bypassable transmission (TCRR-B), the competitive bid rate, a true-up of the competitive bid rate (CBT), and the alternative energy rider (AER).

However, reconciliations of certain bypassable riders could become nonbypassable under the Reconciliation Rider.

The nonbypassable Reconciliation Rider (RR) will initially recover costs of implementing the competitive bid plan, including CBP auction costs, CBP consultant fees, PUCO consultant fees, audit costs, supplier default costs (if any), and carrying costs at the cost of long-term debt. The Reconciliation Rider will also include costs for implementing certain competitive retail enhancements, which are discussed in more detail below.

However, in order to "remedy" the "self-perpetuating, spiraling problem," of under-recoveries in bypassable riders due to customer shopping, DP&L seeks recovery through the nonbypassable Reconciliation Rider of any deferred balance that exceeds 10% of the base recovery rate associated with any of the following true-up riders: fuel, RPM, TCRR-B, AER and CBT.

If the deferral (or reconciliation) piece of any of the above true-up riders exceeds 10% of the base recovery rate, then the portion that exceeds 10% will be included in the next seasonal quarterly true up of the nonbypassable Reconciliation Rider. Further, when the legacy fuel, RPM, and TCRR-B riders are eliminated as a result of 100% auction-based SSO supply as of June 1, 2016, any remaining deferral balance or credit will be included in the nonbypassable Reconciliation Rider at that time.

As indicated above, transmission costs will be split into bypassable and nonbypassable charges. Nonbypassable transmission costs (TCRR-N) will reflect the costs of providing base transmission service such as Network Integration Transmission Service (NITS) and costs associated with PJM's Regional Transmission Expansion Plan (RTEP), Black Start, Expansion Cost Recovery Charges (ECRC), NERC/RFC admin costs. Reactive Supply, TO Scheduling, PJM Scheduling, Load Response Charge Allocation, Generation Deactivation, Michigan-Ontario Interface Phase Angle Regulators, Firm Point-To-Point credits, Non-Firm Point-To-Point credits, and Incremental Capacity Transfer Rights credits. SSO suppliers and retail suppliers will no longer be responsible for such costs.

DP&L's application confirms that the Service Stability Rider, which will recover $120 million, will be nonbypassable. Additionally, the previously reported switching tracker will be included within the SSR, and the deferred DP&L lost revenue due to switching will be recovered from all customers on a nonbypassable basis.

Pursuant to Ohio Rev. Code § 4928.143(B)(2)(c), DP&L asked the Commission to authorize a placeholder Alternative Energy Rider - Nonbypassable to allow DP&L to recover costs of its Yankee solar generation facility on a nonbypassable basis. DP&L asked the Commission to set the charge initially at zero, and to allow DP&L to file an application within six months of a Commission order to establish the level of the charge.

Notably, despite the sought nonbypassable rider for the Yankee facility, DP&L has said that it may meet its SSO alternative energy requirements through the use of the RECs generated by the Yankee solar generation facility. DP&L may also purchase RECs to meet its SSO alternative energy requirements.

As previously reported, DP&L will file a separate application pursuant to Ohio Rev. Code § 4928.17(E) and Ohio Admin. Code § 4901:1-3 7-09 no later than December 31, 2013 to accomplish the transfer of its generation assets. In this subsequent application, DP&L presently expects to request that the Commission authorize DP&L to transfer its generation assets by no later than December 31, 2017.

DP&L has proposed to implement the follow modifications to its Customer Service System (CSS), Electronic Data Interchange (EDI), and Information Technology (IT) systems to enhance the retail market:

1. Eliminate the minimum stay and return-to-firm provisions in its generation tariffs.

2. Implement a web-based portal such that CRES Providers can obtain DP&L customer information in more usable and manageable fashion.

3. Implement an auto-cancel feature to the Bill-Ready billing function, such that when DP&L cancels its charges, it will also cancel the supplier charges on the bill. This change will eliminate customer confusion and will ensure customer payments are posted to the account properly.

4. Remove the enrollment verification that requires a CRES Provider to have the first two digits of the customer name on the account as well as the correct account number.

5. Support Historical Interval Usage (HIU) data requests via EDI.

6. Provide CRES Providers a standardized sync list on a monthly basis