Michigan Sticks with Hybrid Proxy Plant Protocol for PPAs

Consistent with a similar ruling issued two months prior for a different utility, the Michigan Public Service Commission has directed DTE Electric Company to utilize a so-called hybrid proxy plant (HPP) approach in calculating its avoided costs for purposes of pricing purchases of renewable energy from qualifying generation facilities (QFs). The commission noted that the Public Utility Regulatory Policies Act of 1978 (PURPA) requires utilities to execute long-term power purchase agreements (PPAs) with those small power producers deemed eligible for QF status, which generally means a nameplate capacity of no greater than two megawatts. The commission stated that PURPA also provides that such contracts, as well as standard offer tariffed rates, are to reflect pricing terms based on a utility's forecasted avoided costs. 

In the earlier proceeding, which involved Consumers Energy Company, the commission had determined that the HPP method was the most appropriate for assuring that PURPA's avoided-cost criterion was met. The commission said that the HPP method uses a natural gas combustion turbine (NGCT) as a baseline proxy for the capacity element of a utility's avoided costs, but lets a QF select the basis for the energy component (from among three choices). In the Consumers Energy docket, the commission found that the HPP model is the optimum means of assuring just and reasonable payments to a QF while not exceeding the price a utility would have paid if it generated the power itself. 

The commission observed that for DTE, its staff had recommended the NGCT-premised HPP method, just as it had in the Consumers Energy docket. Commission staff had reiterated its position that the use of an NGCT unit as a proxy for the cost of capacity was appropriate because that type of facility can be built quickly, at a relatively low cost, and can be cycled on and off as needed. 

As to the energy component of PPA rates, the approved plan permits the QF to select one of three options: 

1. the locational marginal price (LMP) in the Midcontinent Independent System Operator's wholesale market at the time of delivery; 
2. the utility's LMP forecast over the contract period; or 
3. payment based on the forecasted variable cost of an NGCT unit as determined by the model used to calculate transfer prices under rules designed to allocate renewable power costs in cases concerning a utility's obligation to meet defined renewable energy goals. 

In once again embracing the HPP method as the most appropriate model for calculating avoided costs pursuant to PURPA, the commission also reinforced its earlier conclusion that the purpose of PURPA, and its avoided-cost construct, is not to set prices that reflect the lowest-cost incremental capacity and energy, but to assure nondiscriminatory treatment among QFs by setting prices that are just and equitable and mirror what the utility would have paid if it purchased or built the resource itself. 

Advocating for a method that would produce lower prices to be paid to QFs, the utility had urged the commission to take into consideration the "significantly more challenging business environment" in which DTE operates. But the commission answered that the company had failed to connect how exactly those challenges are exacerbated by DTE's obligation to purchase QF power. 

The commission remarked that one of the challenges DTE is facing (but actually failed to mention) is its need to increase its renewable generation portfolio from 10% to 15% and to provide additional renewable energy to customers under the state's voluntary green pricing program. From the commission's perspective, the availability of QFs willing and able to provide additional renewable energy at no more that DTE's avoided cost should make that particular challenge much easier to surmount. 

In addition to affirming the HPP convention in the DTE Electric case, the commission also considered what the maximum term the utility's renewable energy PPAs should have. To that end, the Michigan commission appeared to buck a developing trend from some other states, which have begun calling for shorter contract terms. 

As an example, in contrast to the 10-year cap placed on PPAs by Montana regulators in June, the Michigan commission approved a maximum term of 20 years for DTE's standard offer contracts. Both state agencies asserted that they had attempted to balance the effect that shorter terms might have on stimulating the development of the QF market against the need to protect ratepayers from being saddled with mandated purchases of power at what might turn out to be higher-thannecessary rates for long periods of time. In the instant case, however, the Michigan commission held that a 20-year maximum would benefit both QFs and the utility by allowing better access to investment and financing as compared to a shorter term. 

As in the Consumers Energy case, the commission also addressed the question of what a utility should be required to pay for QF power during those periods when the utility has no need for additional capacity. After weighing the party positions, the commission accepted an avoidedcost model based on a 10-year planning horizon, such that DTE must procure QF power and include capacity payments in all associated PPAs whenever it is established that it will need capacity at any time during that time period. 

The utility had argued that if it had no need for capacity in the first five years of the planning period, QFs should receive capacity payments based only on a measure of cost as derived from wholesale market transactions rather than a full avoidedcost measure. But the commission rejected that plan, pointing out that 

1. DTE actually uses a far longer planning horizon in making decisions about whether to purchase or build new conventional generation; and 
2. there is significant ratepayer value in deferring large capacity additions through contracting with QFs for incremental capacity instead. 

According to the commission, that last factor is a particularly acute concern with respect to DTE Electric. The commission elaborated that that is because the utility is, in fact, planning a significant increase in its capacity portfolio, at a substantial cost to ratepayers, beginning in the next few years. Re DTE Electric Co., Case No. U- 18091, July 31, 2017 (Mich.P.S.C.).