State Issues Final Order Approving Major Change To Default Service Procurement Plan, To Mitigate Risk Premiums

The Connecticut PURA has issued a final order which adopts major changes to the state's procurement plan for electricity standard service (default service for customers at or under 500 kW), with such changes designed to, among other things, lower risk premiums in default service rates

Specifically, PURA approved a "framework" for "dynamic market purchases", or direct purchases from the ISO-NE market by the utilities (rather than through a third-party wholesale supplier)

PURA's final order sets a non-binding target for dynamic market purchases of 20% of the standard service portfolio, which currently relies on full requirements contracts for 100% of load

The final order recognizes that the utilities have stated that each EDC is not able to implement dynamic market purchases for the October 2026 full requirements procurement

The order requires each utility to "proceed diligently" to implement dynamic market purchases, "at the earliest feasible procurement term," and, "as soon as practicable"

The order stressed that, in being a non-binding target, the ultimate procurement for standard service could rely on higher or lower amounts of dynamic market purchases, based on market conditions. Load not served through dynamic market purchases will be served under full requirements (FRS) contracts (i.e. 80% FRS if dynamic market purchases were used for 20%)

The order requires that a Planning Committee be created at each utility (with members from the EDC's procurement team and state agency stakeholders), and that such Planning Committee shall establish, prior to any standard service procurement, "decision rules, objective comparison metrics, and documented analyses," for the consideration of the received full requirements bids versus reliance on dynamic market purchases

Additionally, the state's procurement manager (PM), with input from the EDCs, OCC, and DEEP, is required to develop a framework that shall, "identify the technical, economic, and market conditions under which dynamic market purchases may be exercised."

The final order states that, among other prompts for dynamic market purchases, "Failed and partially failed solicitations, limited bidder participation, elevated bid dispersion, and material differences between FRS bids and relevant market indicators must be addressed."

"Additionally, objective metrics on bidder participation, bid dispersion, proxy-price comparisons, forward market prices, recently accepted bids, and other objective indicators may be incorporated into the framework. However, rigid thresholds should not displace the Procurement Teams’ and the PM’s professional judgment," the order states

The order finds that additional dynamic market purchases should not be limited to failed FRS bids, stating that uncompetitive full requirements bids, limited supplier participation, elevated bid dispersion, or other prevailing conditions may support the use of an additional dynamic market purchase tranche even when an FRS solicitation has not technically failed.

The final order stressed that the decision to serve more than 20% of standard service load through dynamic market purchases, "should not be made on an ad hoc basis or first determined on bid day."

"Dynamic market purchases above 20% are an authorized procurement option, not a procurement objective. The purchase should be considered only through an advanced, structured evaluation of whether prevailing conditions support a reasonable expected benefit to standard service customers," the final order states

The order provides that, "The PM shall develop the criteria for determining when it may be appropriate for dynamic purchases to exceed 20% in the Procurement Plan Amendment. At a minimum, the criteria shall address market prices and volatility, available FRS bids and supplier participation, projected reconciliation and migration impacts, proxy-price assumptions, customer rate effects, available financial and physical hedges, cost-allocation consequences, and operational feasibility."

With dynamic market purchases, in which the ultimate cost to serve load is established in part in real-time based on the spot markets (plus ancillaries, etc), there is the potential for fixed retail standard service rates, which necessarily must be set in advance based on the full requirements portfolio and an estimate (proxy) of dynamic market purchase costs, to diverge more greatly from the actual wholesale costs that the utilities must recover in rates

The final order does not, however, establish a mid-period reconciliation of standard service rates and costs as a result of dynamic market purchases. Standard service rates are currently fixed for 6 months.

"The Authority does not approve a mid-period reconciliation mechanism at this time. The limited potential benefit outweighs the added complexity, customer confusion, and disruption to rate stability," the final order states

The order notes that, due to the retail market timelines, there may not be enough time for customers to meaningfully receive any benefit from switching in response to a mid-period standard service rate change

"An interim adjustment would ... be delayed by the 45-day supplier-notification requirement. The adjustment may therefore take effect too late to provide meaningful protection before the next regular rate change," the order states

"[T]he proposed interim GSC [standard service] adjustment would address a single reconciliation balance while potentially increasing customer confusion and reducing bill predictability. It could also affect customer migration, altering the load over which reconciliation balances are recovered or refunded and creating additional over- or under-recoveries. The interim GSC adjustment may therefore introduce further instability rather than resolve the underlying imbalance," the order states

The final order also rejects at this time a proposed plus-or-minus 0.5 cent per kWh deadband for any reconciliation (which would defer costs/credits outside of the deadband to a future reconciliation period]

The order finds that no change to the treatment of capacity costs is warranted at this time, given ongoing reviews at ISO New England of capacity-related issues

Notably, PURA approved the use of environmental attributes available under existing PPAs to satisfy the RPS obligation associated with dynamic market purchases. "Applying a market-based transfer price recognizes the value of those attributes while avoiding the costs of a separate market purchase," the draft states

Ancillary service costs for the portion of standard service served under dynamic market purchases (which will be charged to the EDCs as LSEs for such self-served load) are to be reflected in standard service rates, the final order provides

In setting the proxy price to be used in standard service retail rates (to reflect the estimated costs of the dynamic market purchase tranches), PURA adopted the use of the price from the lowest rejected full requirements (FRS) bid from the final standard service solicitation as the proxy price

The final order stresses that, "use of this proxy price-setting method should not establish a continuing preference for over-collection. Actual experience should be used by the PM and Planning Committee to determine whether the methodology reasonably balances the risks of over- and under-collection."

During the proceeding, PURA had considered risk mitigation measures with respect to reliance on dynamic market purchases, such as due to potential large reconciliation rates when actual self-supply wholesale costs and pre-established retail rates diverge

The final order does not adopt any such mitigation measures, stating, "In a potential portfolio of standard service supplied 80% or more by FRS [full requirements] contracts and 20% or less by dynamic market purchases, the Authority finds the price risk to standard service customers associated with the dynamic market purchases to be sufficiently mitigated by the inherent portfolio composition."

If dynamic market purchases in an amount over 20% are used, the order requires the EDCs' Planning Committees to evaluate exposure to market prices, and consider strategies to address such exposure

However, the order provides that, "The Authority does not find that [dynamic market] purchases above 20% automatically require a financial or physical hedge."

"If an additional financial or physical hedge is warranted, the Planning Committee shall evaluate reasonable available alternatives, including Nuclear PPAs, fixed-volume forward energy contracts, other standardized financial products, and physical supply products," the order states

PURA further held that, "The Authority does not adopt a presumption that Nuclear PPAs must be used whenever dynamic purchases exceed 20%."

"Nuclear PPAs should be used only when their expected risk-reduction and customer benefits exceed their costs, implementation burdens, and cost-allocation concerns. Conversely, Nuclear PPAs should not be rejected solely because their costs and benefits are currently recovered from a broader group of customers [the PPAs have non-bypassable cost recovery]. The relevant consideration is whether their use produces a reasonable overall result under the circumstances presented," the final order states

PURA held that any use of the nuclear PPAs for standard service shall, "avoid improperly shifting standard service procurement costs to retail-access or last resort service customers."

However, the final order not address at this time any specific mechanism to prevent cross-subsidization of standard service customers by all delivery customers in cases where the nonbypassable nuclear PPAs are used for standard service

"The Authority agrees that any proposed use of Nuclear PPAs must identify the allocation of associated costs and benefits. The proposal must also avoid improperly shifting standard service procurement costs to retail-access or last resort service customers. Because no specific allocation proposal is before the Authority, the appropriate allocation is not determined herein," the order states

The order does not change the existing timing or frequency of full requirements procurements, as had been proposed by certain parties

The order notes that, as in the current FRS process, full requirements bidders may continue to submit bids covering terms longer than six months, provided that the price applicable to each six-month period is separately stated

Concerning the utilities' costs to implement dynamic market purchases, the final order states, "the costs of dynamic market purchases would be included in the existing GSC and BFMCC [both bypassable] mechanisms and allocated according to the approved methodology for those existing mechanisms." Implementation costs will be subject to PURA prudency review, however

PURA held that changes to standard service delivery periods, and forward purchases for standard service, should not be addressed further in the instant proceeding.

PURA also flatly rejected a volatility mitigation fund.

As proposed, a volatility mitigation fund would retain a portion of standard service over-recoveries for use during later periods when actual dynamic market purchase costs exceed the proxy price.

PURA found that, "a volatility mitigation fund would not reduce procurement costs or hedge wholesale-market exposure. It would only defer the rate effects of actual procurement outcomes."

PURA expressed concern that customers paying into the mitigation fund may not receive its benefits due to migration or other causes (with free riders also a concern, such as those customers joining standard service only after the fund starts paying out)

PURA said that while a volatility mitigation fund may be considered in the future, as experience with dynamic market purchases grows, "Any future proposal should address the equity, affordability, carrying-cost, and cost-causation concerns identified in this Decision. A proposal may also consider alternatives identified by Eversource and UI, including a state-supported mechanism that does not depend on retaining customer over-recoveries."

Docket 12-06-02RE05