Overview
In light of the pending FERC PURPA NOPR, some states have stayed or delayed ruling on pending cases involving PURPA contracts and avoided cost rate, particularly where a standard contract or rate is involved. In two states, however, December 9, 2019 saw significant decisions on PURPA contracts and rates. Although too detailed to fully recap here, the orders reflect the fact that PURPA rates and contracts raise innumerable and complex issues, particularly when utilities claim renewable QFs cause integration costs and developers of hybrid (paired) QFs seek compensation associated with the benefits of adding battery storage to renewable QFs. On January 3, 2020, however, one of the orders, was altered on reconsideration, as arguments that the rates adopted were too low were found to be persuasive.
In Caithness Beaver Creek, LLC, which is pending reconsideration, the Montana PSC -re-examined numerous policies on avoided costs and other issues such as contract length after Caithness and NorthWestern could not negotiate a PURPA contract. Perhaps the most interesting ruling came on the methodology for calculating an avoided cost for energy, as the Montana PSC found good cause to depart from its prior methodology. As the current FERC PURPA regulations still require a fixed price for energy, the Montana PSC decided to adopt a forecasted rate based on hourly modeling and marginal costs to serve load so that avoided energy costs would equate to the running cost of NorthWestern’s highest-cost resource needed to serve load in each hour: $0 if load is served with must-take or intermittent resources with no variable costs (solar, wind, hydro); the variable costs of the marginal generating resource if load is served with NorthWestern-dispatched generation; or the market price if load is served by market energy purchases.
The Montana PSC found hourly modeling does not obscure important intra-monthly fluctuations in energy load and supply availability and costs that have substantial impacts on avoided energy costs. The Montana PSC used a marginal cost to serve load for valuing NorthWestern’s avoided energy costs because, in certain instances, QFs may provide more than NorthWestern requires to meet its total system load and the purchase rate should only include payment for energy or capacity which the utility can use to meet its total system load. It found utilizing marginal cost to serve load more appropriately ensures customer indifference to QF power purchases. It will be interesting to see if Caithness eventually appeals this avoided energy cost approach.
Other controversial aspects of the case included the PSC’s decision to not budge from its existing position that putting a price on carbon emissions is pure speculation and that it is thus unreasonable to force ratepayers to pay for a cost that does not exist.
The contribution the batteries would provide permeated several litigated issues, but the Montana PSC was not persuaded to assign much value to the hybrid nature of the QF. One issue as to which the hybrid project did benefit from its battery technology was in contract length. Although certainly not viewed as a QF-friendly state, the Montana PSC does abide by the notion that long-term contracts are necessary for QFs. Its policy is that “an appropriate contract length for a QF exists in the window between a base level at which a QF can obtain financing and the point at which customers are subjected to an intolerable level of forecast risk.” Although the Montana PSC had tended toward 15-year contracts in recent years, a 20-year contract was awarded due to the unique and unproven nature of the project as well as the additional capital and O&M investment that will be required due to the project having batteries.
In an order implementing the South Carolina Energy Freedom Act, as to Dominion Energy South Carolina, which order also is under reconsideration, the SC PSC admitted that the avoided cost rates it set were priced very favorably to ratepayers compared to historical experience, thus lowering the risk of overpayment. Indeed, on rehearing, it has been argued that the rates re far below those of other South Carolina utilities.
The SC PSC adopted Dominion’s Difference in Revenue Requirement approach to calculating avoided costs for capacity and energy, which is based on running models of cases with and without the QF purchase. A primary issue of controversary was the impact of solar energy on capacity needs; the SC PSC found that solar QF energy will have an effect equal to 4% of its nameplate capacity on the need for future capacity. Another controversial issue was the cost of integrating solar (the level of the Variable Integration Charge and the Embedded Integration Charge was at issue); the SC PSC put off making a decision on several issues relating to integration costs and the reserves needed until a later proceeding.
On January 3, 2020, however, the SC PSC issued a directive in the docket, reversing course on many key findings, including the 4% ruling on capacity. The PSC reduced the interim Variable Integration Charge and the Embedded Integration Charge associated with intermittent resources and reinforced that the charges were temporary and subject to true-up. The SC PSC also made clear that a project could mitigate the need for the charges with battery storage or other means. The standard offer energy rates were raised. Moreover, the 4% capacity finding was increased nearly three-fold to 11.8%. The contract duration term was to be re-examined as well. South Carolina had been seeing a boom in solar development; evidently, the December 9, 2019 decision was viewed as so favorable to Dominion such boom would grind to a halt in the portion of the state served by Dominion Energy South Carolina. This proceeding will continue.
