TODAY’S STUDY: Smarter Electricity Rates Allow More New Energy

Current Developments in Retail Rate Design: Implications for Solar and Other Distributed Energy Resources

Andrew J. Satchwell, Peter A. Cappers, and Galen L. Barbose, July 24, 2019 (Lawrence Berkeley National Laboratory)

Executive Summary

Retail electricity pricing is evolving in the context of broader shifts in how electricity customers pay for grid services and how they are compensated for customer-sited generation. This evolution has been prompted by a broad set of factors, chief among them being: widespread adoption of advanced metering infrastructure (AMI), increased customer investment in solar and other distributed energy resources (DERs), concerns about utilities’ fixed cost recovery and revenue sufficiency in an era of flat or declining load growth, and significant changes to utilities’ hourly net load profiles and operational needs as greater amounts of variable renewable energy (VRE) resources connect to the grid.

This report discusses five current retail rate design trends among residential and commercial customer classes that have emerged, at least in part, in response to those drivers, and uses case studies to illustrate key motivations, variations in rate design, and aspects of implementation experience. Highlights from our review of these rate design trends include the following:

• Increased pursuit of residential time-based rates: Though the federal government enacted legislation over forty years ago asking states to consider the appropriateness of time-based rates, currently only around 3% of residential electricity customers see any temporal variation in the price of electricity (Hledik et al., 2017). As advanced metering infrastructure (AMI) deployment progresses, broader and stronger regulatory support for the adoption of time-based rate options is beginning to emerge. For example, based on the results of their two-year residential pricing pilot, the Sacramento Municipal Utility District (SMUD) is currently transitioning all of its residential customer to a default time-of-use (TOU) rate, which has a peak-period shifted to late afternoon and early evening hours (5-8 PM) (SMUD, 2017). Starting in 2010, Oklahoma Gas & Electric (OG&E) began to test with its residential and small commercial customers a variant of a TOU rate, where the peak price changed daily to better reflect contemporaneous market conditions. That pilot was so successful that the utility gained authorization from its regulators to offer the rate starting in 2013 on a voluntary basis to all its residential customers, with the goal of enrolling 20% of them within three years. As of December 2016, OG&E had enrolled about 107,000 residential customers in its SmartHours Variable Peak Pricing (VPP) rate, representing 19% of its residential customer base (AEG, 2017).

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• Development of rates and programs to promote midday load building: Utility system planners and system operators in some regions are anticipating, if not already observing, steep declines in load during the morning and steep inclines in late-afternoon/early-evening periods, due to solar PV resources on the bulk power system. This may result in wholesale power costs dropping precipitously during midday hours and curtailment of renewable generators (Seel et al., 2018). One strategy utilities have considered to assist in grid management employs TOU rates designed with very low priced (“super off-peak”) periods that coincide with these low cost midday hours (sometimes referred to as matinee pricing). California’s investor-owned utilities are currently testing whether residential customers will increase their usage in response to such super-off peak prices as well as reduce or shift usage away from higher-priced peak periods that primarily cover late afternoon and early evening hours, year-round (CPUC, 2015). Alternatively, a utility could pursue programs that provide direct financial incentives for customers to use more load when there is excess generation on the system. Arizona Public Service (APS) recently filed a proposal to implement a reverse demand response program to promote load building during certain periods of time in order to avoid curtailing renewable energy production (APS, 2017). This proposal was filed in September 2017, and is currently awaiting decision from the Arizona Corporation Commission.

• Increased application of residential three-part rates: While three-part rates (i.e., demand charges, along with volumetric energy charges and fixed customer charges) have been largely confined to commercial and industrial customers, utilities have become increasingly interested in extending demand charges into the residential sector as well, with the stated purpose of better aligning rate design with underlying cost causation and stabilizing fixed-cost recovery. Within the residential sector, demand charges have been offered mostly on a voluntary basis, but several utilities have implemented or proposed such rates on a mandatory basis, at least for customers with rooftop PV or other DERs. APS has perhaps the longest running experience among investor-owned utilities (IOUs) with voluntary demand charge rates for residential customers and recently launched a new set of tariff options, with 17% of customers opting onto one of the demand charge rates. Analysis of a previous APS tariff offering found that customers on the demand charge rate reduced their billing demand by roughly 11%, on average. Salt River Project (SRP) also recently introduced a mandatory demand charge rate for new rooftop solar customers. Customers on SRP’s new demand-charge rate have reduced their billing demand by 11% on average, potentially enabled by the sizeable contingent of recent solar adopters that also installed storage. Despite those demand management efforts and opportunities, new solar applications are roughly 20% below their level prior to implementation of the new tariffs.

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• Development of new net-metering alternatives: Many states have undertaken reforms of existing net energy metering (NEM) tariffs, driven chiefly by concerns about cost-shifting between NEM participants and other ratepayers, and to incentivize customer DER investments that provide greater benefits to the broader electric system. Among states that have adopted an alternative to NEM, net billing has been, by far, the most common approach—whereby customers can continue to offset contemporaneous usage with DERs, but any exported energy is compensated at some designated grid-export rate. New York’s Value of Distributed Energy Resources (VDER) tariff represents a relatively sophisticated form of net billing, with grid export rates that vary by time and location, and a phased implementation schedule for different market segments. Hawaii has also moved to net billing, with a range of transitional tariff options, and has seen a sizeable portion of applications in the past year opt for solar+storage configurations in order to qualify for morefavorable grid export prices and other terms.

• Development of new electric vehicle-specific rates: States and utilities with some of the highest growth and interest in supporting electric vehicle (EV) adoption are introducing retail rates specific to EVs. In addition, some EV-specific rates are designed to potentially better direct charging behaviors in ways that minimize the grid impacts and also potentially benefit the grid from such electric-intensive end-uses. EV-specific rates primarily differ as to whether they include demandbased or time-based energy charges, a potentially contentious detail that may incentivize or deincentivize certain forms of EV charging (e.g., demand charges may particularly impact public charging by penalizing fast chargers, which are demand intensive). Georgia Power‘s rate offers EVowners a time-based (TOU) energy charge applicable to the entire household consumption. This contrasts with Austin Energy’s residential fixed, monthly fee limiting EV charging to off-peak hours only. San Diego Gas and Electric (SDG&E)’s rate for EV charging at multi-unit dwellings and workplaces includes locational costs based on California ISO day-ahead market prices and distribution feeder load.

Each of the five rate design trends entails potentially significant implications for solar and other DERs, in terms of both the quantity and type of deployment that may occur in the future. As shown in Table ES - 1, the potential near-term impacts on DER deployment (which, in some cases, have already been observed) vary significantly depending on the particular rate design and type of DER: either accelerating or constraining deployment, and to varying degrees. These near-term impacts also depend critically on specific tariff design details (e.g., the timing of TOU peak periods or the type of demand charge adopted), as indicated by the ranges shown in the table for any particular rate reform and DER

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In considering how these various rate reform trends may impact DER deployment, three broad themes emerge:

• DER impacts depend critically on the specifics of the tariff structure. Even if obvious, it cannot be over-stated how important are the specifics of any particular rate design in assessing the potential impacts on DER deployment. Among the rate design trends discussed in this report, this includes details such as: the timing and peak-to-off-peak pricing differential under time-based rates, the choice between intermittent vs. continuous incentives to increase midday load, the use of coincident vs. non-coincident demand charges, the specific price paid for grid exports under net billing rates, and whether or not EV-specific rates are sub-metered vs. applied on a whole-house basis. Details such as these dictate not only the magnitude, but in some cases also the directionality of impact for certain DERs.

• Flexible DERs generally benefit more under emerging rate design trends. DERs exist along a continuum of flexibility, ranging from those with largely fixed load shapes (energy efficiency (EE) and PV), to those with some level of discretion in how they are operated (EVs and certain other forms of electrification), to fully dispatchable resources (storage and certain forms of demand response (DR) and electrification). As evident by a quick glance at Table ES - 1, most emerging rate reforms tend to support greater deployment of flexible DERs (e.g., storage and DR), while often constraining adoption of less-flexible resources (e.g., PV and EE). This outcome is driven by the general movement towards rate structures with greater temporal granularity, which naturally tends to encourage price-responsive resources.

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• Emerging rate designs generally encourage load building (during specific times of the day). Though only one of the five rate design trends discussed in this report is explicitly intended as a tool for load building (“Development of rates and programs to promote midday load building”), most of the other rate design trends also incentivize load building, whether in the form of EVs, other types of electrification, or energy storage (which increases net electricity consumption due to round-trip losses and ancillary loads). The incentives for load building are often concentrated during particular times of the day, though depending on their design, three-part rates may encourage load building across a fairly broad range of hours. In contrast, the emerging rate designs discussed in this report generally tend to constrain growth of DERs that reduce consumption of grid-supplied electricity (EE and, especially, PV). This outcome is driven partly by the general movement toward greater levels of attribute unbundling and temporal granularity that better reflects marginal costs. Load building is also a natural response on the part of electric utilities to slowing sales growth and ongoing concerns about revenue erosion from EE and PV, and electrification is a strategy that some state policymakers and regulators have endorsed for addressing their greenhouse gas abatement goals.

Regulators engaged in retail rate reform efforts may wish to consider explicitly how new rate designs may impact deployment trends among different types of DERs, weighing those impacts against the many other considerations and stakeholder perspectives that regulators must balance in establishing utility rate structures.

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