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Developing a comprehensive energy project is a complex endeavor requiring facility auditing and utility analysis along with a detailed scope development. During the development process, most developers focus on scope and pricing while performing the utility analysis portion at the basic blended-rate level. The accuracy of energy cost-savings from a blended-rate analysis depends on the complexity of the utility rate structure. For simplified flat rate tariffs, blended rates multiplied with estimated total kWh savings will yield an acceptable annual cost-savings.
However, for complex utility rate tariffs, such as California investor-owned utilities (IOUs), blended-rate analysis may predict results that are way off from the actual savings. Complex utility rate structures usually have fixed, demand, and energy charges along with seasonal and time-of-use (TOU) breakdowns. Furthermore, all of these various component charges have subcomponents. For example, energy charges are subdivided into seasonal and time-of-day periods as well as by transmission, distribution, etc. Additionally, other rate tariff attributes such as demand ratchet, net energy metering, demand response events such as peak day pricing, and more complicate the analysis. The California Public Utilities Commission’s (CPUC) proposed decision on revising net energy metering tariffs and sub-tariffs (NEM 3.0) provides an example of where the complexity of the rate tariff necessitates a nuanced model to achieve accuracy of energy cost-savings that takes into account a number of factors. The proposed changes: • Replace the retail rate-based export compensation formula with the export compensation rate based on a calculation of utility-avoided cost as reflected in the annually updated Avoided Cost Calculator • Following a five-year ‘lock-in’ period, export compensation for solar will be based on average monthly avoided cost values from that year’s Avoided Cost Calculator • Require all NEM customers to take service on TOU rates that have a “high differential between summer weekday peak and summer weekday off-peak periods” in order to encourage usage during lower-priced hours when the solar system is producing and/or charging storage, rather than at expensive times when the grid’s energy supply is constrained • Add a monthly “grid participation charge” of $8 per kilowatt for homes (but not businesses) that install solar • Preserve the current NEM 2.0 approach to recovery of non-by passable charges (public purpose program, nuclear decommissioning, competition transition charge, and DWR bond charge) from NEM customers, and reject recommendations by some parties to expand this list to include additional categories of charges • Adopt a new residential Market Transition Credit to temporarily make up part of the decrease in export compensation rates compared with NEM 2.0, and serve as a “glide path” to the successor tariff • Replace the NEM 2.0 netting intervals (15-minute for nonresidential and 1 hour for residential customers) with instantaneous netting, where all recorded imports are charged at the retail rate and all recorded exports are charged the export compensation rate • Preserve annual true-ups for both residential and non-residential NEM customers, meaning credits can be carried forward to future months within a 12-month billing period — customers will be required to pay all incurred charges every month, but netting will occur annually instead of monthly as previously proposed by some parties "Accurately modeling the correct charges from interval data and appropriate tariff is very important." • Address equity for low-income customers by waiving the grid transition charge and allow for TOU rate flexibility for 10 years — additionally, the proposed decision adopts an equity fund with an annual cap of $150 million over a four-year period • Determine that the virtual NEM and NEM aggregation sub-tariffs will be revised to mirror the new tariff structure (Since many VNEM customers are renters, they will be allowed to choose any applicable TOU rate, and the VNEM tariff will allow multiple solar arrays on one property to be treated as one generator with credits allocated across the property) • Decline to adopt a successor tariff specifically for community distributed energy resources because community solar is currently under discussion in other proceedings • Require homes that already have solar panels to switch from the existing net metering program to the new program described above — known as “net billing” — no later than 15 years after their systems were installed (Low-income homes could keep operating under the more favorable terms of the old program for 20 years after installation) • Offer all existing NEM 2.0 customers a rebate to invest in storage if they voluntarily switch to the successor tariff within four years from the time the storage rebate becomes available (During the first year the storage rebates will be $0.20/Wh, and it will decrease by 25 percent a year over the subsequent four years — the rebates will be funded through a Storage Evolution Fund funded through utility distribution charges) The uncertainty and proposed changes to NEM rates create a chaotic reality for the solar economic model. The utility economic model starts with 15-minute interval kW usage data and the applicable utility rate schedule to simulate a Business as Usual (BAU) scenario. Then, the model evaluates the kW data at each 15-minute interval and applies the appropriate demand and energy charges based on the on-peak, mid-peak, and off-peak rates associated with the summer or winter season. This effort would be tedious if done by hand for over 35,000 data points, but a computer tool can process these calculations in a few seconds. The model summarized the demand, usage, and charges for all 12 months similar to how the utility would calculate the billing for their customers. The BAU case can and should also be calibrated to the actual utility bills to ensure a good baseline. Accurately modeling the correct charges from interval data and appropriate tariff is very important. However, it is even more important to estimate accurate savings from the proposed measures and solutions. This requires additional steps in developing interval savings (energy efficiency measures) and/or generation (generation measures) profiles utilizing industry energy modeling tools (e.g., eQuest, SAM, PVSyst, etc.). For example, an hourly photovoltaic (PV) production profile is modeled using previously mentioned tools with specific resource data, module, inverter, and electrical information. The difference of the BAU kW demand profile and the PV generation profile results in a net post-measure kW demand profile. The utility economic model is repeated for the post-measure profile to predict the demand, usage, and charges for this post-case. The simulation results in the expected post-PV charges that the customer can expect to see from the utility after they install the PV systems. The annual utility savings result from comparing the post-case against the BAU baseline. Furthermore, the utility economic model can run sensitivity analysis on various rate schedules (such as renewable Option Rtariff) and other parametric perturbations. Overall, uncertainty remains as there is little consistency among states about exactly what policy changes to make to revise or replace traditional NEM programs. The situation is likely to get even more complicated as increasing DER technologies hit the market. In the near future, attention could shift from currently accepted tariff arrangements for individual customers with onsite generation to distributed energy blends that can produce compound benefits for multiple customers, the grid as a whole, and society at large.
