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How far can we go with wind and solar?

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In this era of urgent and ambitious climate goals, most paths to a decarbonised power system feature high shares of variable renewable energy, primarily wind and solar. To avoid high costs, new tools to capture the benefits of these clean resources are needed, to manage the new loads from electrification of heating and transport, and accommodate increasingly distributed system sources. Ensuring reliability will require faster response times and greater flexibility.

The International Energy Agency’s Wind Technology Collaboration Program Task 25 has explored these formidable challenges in their report Design and operation of energy systems with large amounts of variable generation. On 30 March 2022, the Electrification Academy welcomed lead author Hannele Holttinen to share the findings of IEA Wind TCP Task 25. She drew on the extensive information gathered in the report to share:

  • Recent experience and study results from 17 countries on operating and planning systems with large amounts of variable renewable energy sources.
  • How net-zero plans affect power system planning and operation.
  • How to push limits towards near-100% renewables.

 

Rate-Making Principles and Net Metering Reform: Pathways for Wisconsin

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A growing number of states have considered reforms to their net metering practices in recent years, a period of decreasing prices for distributed energy resources, rapid changes in technology and evolution of the electricity system. 

Depending on its design, a net metering program can advance specific policy goals while maintaining sound principles of rate design. Trade-offs in rate design are inevitable as regulators balance different priorities, such as rates that accurately reflect cost causation and rates that are simple for customers to understand. Reliance on long-standing rate-making principles will be key to prudent decision-making. 

This paper was produced for the Wisconsin Public Service Commission as part of its review of the state’s net metering practices. 

The authors examine net metering approaches in the context of general rate-making principles and policy goals. They then explore considerations associated with specific design components of net metering tariffs — including eligibility, metering, netting intervals and customer buyback credits — and the methods used to calculate fixed, energy-based and demand-based charges. The final section details recent net metering reforms in seven states: North Carolina, South Carolina, California, Arizona, Minnesota, New York and Michigan.

The Complex Landscape of Net Metering Reform in California: Ensuring A Smart TOU Rate Foundation

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California, long a leader in rooftop solar, is now wrestling with the complications — as illustrated by the current debate over the California Public Utility Commission’s proposed decision on “net energy metering 3.0,” released last month. Before the end of 2021, we began a series of blogs looking closer at this issue by noting that much of the public debate over the proposed decision has focused on the new “grid participation charge,” which would be structured as a monthly fee per kW of installed capacity.

Another issue under consideration, on which we’ll focus in this second installment, is time-of-use (TOU) rates.  Getting TOU rate design right should be emphasized both in the short term — as an alternative to a large grid participation charge — and in the context of longer-term rate design reform. In short, ensuring that TOU rates for new DER customers have sufficiently low daytime prices is likely to be a more economically efficient way to reduce cost shifts.

The proposed decision does have a brief discussion about the importance of bigger on-peak/off-peak price ratios in TOU rates, and it imposes a requirement that new solar customers go onto such a rate. The proposed decision lists an existing rate that qualifies for each of the three investor-owned utilities, but it does not show those rates or discuss their structure. Those rates are:

These rates do have a bigger on-peak/off-peak price ratio than other TOU rates available in California, but that should not be the only consideration in the construction of a fair and efficient TOU rate. The time period structure, namely the hours that are on-peak, off-peak, and other designations, and the relative levels across each period are all important as well. The 2021 PG&E EV2-A rate in the summer is shown in Figure 1.

Figure 1: PG&E Summer Price Structure Under the EV2-A Rate in 2021

Under any DER compensation structure where a customer can reduce their bill with lower imports from the grid, a substantial portion of the compensation for installing solar will come from the retail rate during daytime hours. As shown in Figure 1, that rate was 19 cents per kWh for PG&E in 2021 and is now 21 cents in 2022. Under the SCE TOU-D-PRIME rate, the daytime kWh rate is 19 or 20 cents per kWh, depending on the season. The SDG&E EV-TOU-5 rate has a more complex structure, but in the summer the daytime kWh rate is even higher, now at 39 cents per kWh in 2022. To the extent that solar customers are overcompensated, and thus causing costs to be shifted unfairly to other customers, this would be a major reason why. If the daytime kWh rate can be reasonably lowered, it could address a substantial portion of any cost shifting and substitute for other potential charges on DER customers, such as the grid participation charge.

The goals of TOU rate design are much the same as all rate design, and indeed utility regulation generally. The desire of economic efficiency must be balanced with the need for customer understanding, costs must be allocated equitably across all customers, and overall revenue levels must provide the utility a reasonable opportunity for a fair rate of return. Compared to flat volumetric kWh rates, TOU rates are attempting to better correspond to predictable fluctuations in the marginal costs, both short- and long-run, of the electric system. Seasonal distinctions can also be important in a TOU rate structure, although such distinctions are possible in simpler rates.

In California and other states where solar is a major part of the resource mix, a particular pattern for marginal costs (in this context, referred to “avoided costs”) is emerging. A longstanding process at the CPUC has led to the annual submission of an “Avoided Cost Calculator” by the consulting firm E3. While the 2021 ACC shows an avoided cost pattern for 2022 that roughly tracks PG&E’s EV2-A rate, by 2024 a different pattern starts to emerge. The daytime hours start to have distinctly lower avoided costs and this trend grows over time. An efficient TOU structure will track these avoided cost patterns with lower prices during daytime hours.

Why does the cost structure expected in California in a few years matter for rate design today? First, anticipating where rate design needs to go in the future is helpful for considering changes over time. Many solar programs have guaranteed customers that they can stay on a particular rate structure for a given period of time to avoid adverse financial impacts. Under those circumstances, it would be wise to implement a rate structure that reflects expected conditions in the future.

Second, these particular rates drive much of the other analysis in the proposed decision about cost shifting, as well as the grid participation charge and the market transition credit. For example, a major reason that SDG&E customers do not get a market transition credit under the PD is likely that the high daytime kWh price in the summer that provides much of their compensation is so generous. If a new rate with lower daytime prices were to be implemented in two years and new solar customers were required to go on that rate, it would upend all of the analysis that went into structuring the grid participation charge and market transition credits.

A third, perhaps more technical, reason is that when you are structuring cost recovery, the relative price elasticity of demand can be considered. As solar costs have declined, overall daytime net consumption has become more elastic (e.g., readily responsive to prices) exactly because of the option to install solar. This reason alone may be sufficient to get out in front of these issues and reallocate revenue collection away from daytime hours to other parts of the rate.

This shows why changing TOU rate structures, particularly with lower daytime prices, is a superior option to the grid participation charge. Hawaiian Electric has already structured some of its TOU rates to have the lowest prices in the daytime, as shown in Figure 2.

Figure 2. Hawaiian Electric Residential TOU Rate for January 2022

Hawaiian Electric Residential TOU Rate for January 2022

While both methods can correct for a cost shift in a spreadsheet model, the grid participation charge is likely to push customers to shrink their solar systems and, even worse, avoid interaction with the grid. A lower daytime price, on the other hand, helps shift load — particularly flexible loads like EVs and battery storage — to the daytime when generation resources are expected to be abundant and relatively low-cost. This is why rate design was one of RAP’s strategies for Teaching the Duck to Fly.

It is important to note that the correct daytime price for these rates should not necessarily drop all the way to the 3-4 cents of avoided costs shown in the E3 avoided cost calculator. First, an extraordinarily low price in the daytime would by itself undercut the economics of solar installations, so the impact on adoption rates should be considered. Second, an extraordinarily low price in the daytime might spur a customer overreaction — moving significantly more consumption than might be expected to the daytime. As a result, the principle of gradualism likely dictates that the pace of change should be moderated appropriately.

Furthermore, the E3 avoided cost calculator has many good features, but it likely does not include full long-run marginal costs for delivery. For example, one expert, testifying in the NEM 3.0 docket on behalf of agricultural electricity consumers, argued that current methods ignored the long-run marginal cost of new transmission needed to deliver utility-scale generation and estimated that marginal cost at 3.75 cents per kWh. Including this type of marginal cost is crucial to establish fair competitive terms between utility-scale solar and local resources. Otherwise, the scale is unfairly weighted towards the side of utility-scale resources. While the E3 avoided cost calculator indicates that there are marginal costs for transmission capacity in the evening peak hours, there are no marginal transmission capacity costs in the daytime hours. If that is the case, this would indicate an issue that should certainly be explored and corrected in the future.

Unfortunately, changes to TOU rate structures were not considered at all in the proposed decision and were not raised prominently in the docket. The solar industry and its allies worry that creating new rate designs that only apply to solar customers risks unfairly singling them out. RAP believes that any new rate structures should be fairly and efficiently designed and should be technology-neutral in order to be applied to a broad swath of customers. On the other side, the utilities focused on their proposal that became the grid participation charge, an option that appears to be unfair and inefficient. If the CPUC declines to adopt the current proposed decision, restructuring the TOU rates would be a sensible option to put on the table, along with other options discussed in our first blog in this series. At a minimum, considering how future reforms to TOU rate structures would require changes to the grid participation charge is necessary.

Forward-looking TOU rates that include lower daytime prices offer an opportunity to advance NEM reform goals while improving customer incentives. More generally, technology-neutral rate design reforms should be the path forward, not the arbitrarily sized installed capacity charges designed to claw back revenue in the proposed decision.

The Complex Landscape of Net Metering Reform in California: Why an Installed Capacity Charge?

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Rooftop solar in California has grown from an infant industry two decades ago to a 10-gigawatt resource that contributes significantly to customer and electric system needs today. The state is blessed with ample sunshine in many regions, and its urgency on this and other clean-energy innovations was born out of the energy crisis in 2000 and 2001, as well as the need to address climate change and improve public health. But a proposed range of reforms to net metering for residential rooftop solar has prompted debate about the future of that important market segment, as well as the broader trajectory of state energy policy.

Full retail rate net energy metering with monthly netting (“traditional NEM”) — the method initially used in nearly every U.S. state, including California — is easy to implement and understand. Traditional NEM, which opted for simplicity over precision and was intended to kick-start an infant industry, might not be ideal from the perspectives of efficiency or fairness, but the extent of those problems depends on the level and design of retail rates, as well as the overall resource mix, load patterns, and customer solar adoption levels.

The maturation of the solar industry and the modernization of the electric grid make an evolution from traditional NEM to more efficient and sophisticated rate designs both possible and desirable. The exact speed of that transition, and exactly which direction to head, is not necessarily obvious and involves tradeoffs that policymakers and stakeholders should understand and debate fully. RAP recently released a report for the Michigan Public Service Commission that seeks to help Michigan regulators and policymakers understand these tradeoffs as they consider improving their rate designs for distributed energy resources (DERs), as well as the broader tariff specifications and DER program structures.

In 2016, California took a substantial step away from traditional NEM to “NEM 2.0.” That step required solar customers to be on a time-of-use (TOU) rate along with other reforms. All else equal, those reforms were designed to reduce the level of compensation for a new solar customer. Residential solar installations dropped modestly in 2017 but the pace of residential installations has grown steadily since then. On Dec. 13, the California Public Utility Commission’s proposed decision on NEM reform signaled a new stage in this debate. The proposed decision found there has been a significant cost shift from new residential solar customers to non-participating customers under NEM 2.0 and includes a wide range of additional reforms to rate design for new solar customers.

These proposed reforms are well intended, and many have substantial merit — including more differentiated time-of-use rates, value-based export credits, encouragement of solar plus storage, and a range of equity measures. More controversially, the proposed decision included a new “grid participation charge,” which is structured as a $/kW monthly fee on installed capacity for new residential solar customers. A new “market transition credit,” structured as a $/kW monthly credit on installed capacity, would partially offset the grid participation charge temporarily for customers of two of the three utilities, at a level designed to achieve a 10-year payback period for new solar installations.

The basic concept of the grid participation charge is not new. It has been debated before and can be generically described as an installed capacity charge. An installed capacity charge is not tied to any reasonable metric of the size of the customer or their impact on or usage of the grid, but is primarily a way to spread certain categories of costs. The direct incentive provided to customers by an installed capacity charge, all else equal, is to install fewer kW of the resources covered by such a charge. In this case, the market transition credit is attempting to partially counteract this effect by ensuring a reasonable payback period for new customers. In that context, it is important to consider whether such a spreadsheet analysis is reasonably accurate and whether there are more qualitative considerations, such as the complexity of the newly proposed rates, that could further hinder adoption.

New York is implementing a similar rate structure for new residential rooftop customers starting in January 2022, which has been labeled a “customer benefit contribution” charge. This charge is designed to cover a smaller set of program costs, namely energy efficiency and clean energy programs as well as low-income discounts. New York’s situation is different: Without its advanced metering infrastructure fully deployed, more sophisticated rates are difficult to implement. The New York Department of Public Service previously estimated that this new charge will be between $0.69 and $1.09 per kW (direct current) of installed capacity, depending on the utility. Final rates, going into effect next month, were recently filed and range from $0.72/kW to $1.33/kW. This means that the size of California’s proposed $8/kW charge for installed capacity is unprecedented, even if it is effectively reduced to $4 or $6 per kW by the market transition credit in the first year of this new structure for two of the utilities.

Jumping into such unexplored territory comes with risks. History shows that rate designs like this spur customers and vendors to find innovative workarounds. For example, customers may try to avoid this new charge by fully disconnecting from the grid. While unlikely for many customers today, it may become a more popular option if costs for storage continue to fall dramatically. Alternatively, customers may be able to set up their solar and storage systems to avoid exporting to the grid and thus avoid any need to notify the utility and be exposed to the grid participation charge. Solar installers have experience with both of these options in Hawaii. Such behavior is likely suboptimal from the societal perspective, and would likely cause significant cost-shifting to other customers. The CPUC could try to prevent these reactions, but this could just push such behavior further underground. Other unintended consequences will also likely arise.

Of course, the proposal for the grid participation charge cannot be evaluated in a vacuum — without a comparison to the relevant alternatives. Regulators should be guided by this principle for efficient rate design (which takes on increasing importance as customers have more options to invest in generation, storage, and load controls): Rate design should make the choices a customer makes to optimize their own bill consistent with the choices that would minimize system costs. Continued reforms to residential time-varying rates is an important option we will explore more fully in a follow-up blog. For now, we note several other rate design options that can address cost shifts from solar distributed generation in a manner similar to the grid participation charge. These should be considered instead of an installed capacity charge, or in combination with a small installed capacity charge:

  • Reasonably sized customer charges ($5 for low-income customers and multifamily building residents, $10 for everyone else);
  • A distribution flow charge on both inflows and outflows;
  • A demand-based or connected load charge to cover line transformer and other site infrastructure costs (approximately $1-2/kW); or
  • A higher minimum bill.

RAP has long advised against major reliance on large customer charges and demand charges for efficiency and equity reasons. In many states and for many customer classes, these charges are far too high. But within proper limits, these options all have a stronger cost causation argument than an installed capacity charge. The distribution flow charge, defined as a cents-per-kWh rate on both imports from and exports to the grid, has not been implemented by any state utility commission, but is a concept that RAP put forward in our report for the Michigan PSC as well as a 2013 report on distributed generation tariff design. Demand charges can also be more difficult for customers to understand and manage than other types of rates, although this can be mitigated with education efforts and data provision.

Ideally, these options would be considered as part of broader reforms to rate design for residential customers. Not all residential customers need to be exposed to more complex rates, however. Another idea discussed in the Michigan report is segmenting the residential class into an “advanced” category and a “basic” category. That way, a broad swath of the residential class could be moved onto more sophisticated and efficient rates without risking adverse impacts to low-income and low-usage customers. Broader residential rate design reform was not a focus of the current California proceeding, but it should be considered as the full CPUC takes up the proposed decision.

The grid participation charge, and other alternatives to address similar issues, is not the only important public policy concern as California considers reforms to its DER program. RAP will follow up with additional blogs in this area in January, discussing issues such as the structure of time-of-use rates, the newly proposed value-based export credit system, community solar and locational value.

Advancing Storage: Progress in Markets and Regulation

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In a presentation for the National Association of State Energy Officials, Richard Sedano discussed the key role of regulation in assuring the successful deployment of storage technology as a flexible and cost-effective grid resource.

Rate Design and Net Metering Reform

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​In a presentation to the Vermont Public Utility Commission, Mark LeBel discussed smart rate design principles and considerations for net metering reform.

Smart Rate Design for Distributed Energy Resources

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​In a presentation for the Michigan Senate Committee on Energy and Technology, Mark LeBel discussed smart rate design principles and pathways for distributed energy resources.

Building a Next-Generation Mix of Energy Resources: Procurement Best Practices

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​In an interactive webinar presentation, panelists discussed a “next-generation” approach to utility procurement and evolving best practices, based in part on recent work done by RAP and RMI. The webinar offered recommendations on how to design clear rules for procurement processes that consider all available resources, are aligned with both utility and public-policy objectives, and result in outcomes that offer the “least regrets.​”