Chapter 9
Bringing DER Into the Mainstream: Regulations, Innovation, and Disruption on the Grid’s Edge
Jim Baak Vote Solar, Oakland, CA, United States
Abstract
This chapter highlights the challenges that regulators, utilities, DER providers, and consumers face in balancing competing interests to enable deployment of DER for the benefit of the grid and utility ratepayers. By drawing from the experiences of California and New York, it illustrates different regulatory approaches and offers insights on how to balance competing stakeholder needs while improving the reliability and resilience of the grid. It describes the significant challenges and opportunities of integrating higher levels of DER deployment and the steps necessary to achieve this outcome, which call into question not only conventional grid planning and operations, but also traditional utility business models.
Keywords
Distribution Resources Plan
distributed energy resources
utility business model
hosting capacity
Integration Capacity Analysis
grid integration
locational net benefits
grid modernization
distribution marginal costs
distributed energy market
Utility of the Future
1. Introduction
Thomas Edison and Nikola Tesla were pioneers and fierce rivals. Edison, a proponent of direct current, electrocuted live animals to demonstrate the dangers of Tesla’s alternating current for transmitting electricity. But there is one thing they both had in common—they both saw a future where renewable energy would dominate.
In 1931, Edison described his vision of the future this way:
We are like tenant farmers chopping down the fence around our house for fuel when we should be using Nature’s inexhaustible sources of energy—sun, wind and tide. … I’d put my money on the sun and solar energy. What a source of power! I hope we don’t have to wait until oil and coal run out before we tackle that.1
Likewise, on the issue of harnessing the sun’s power, Tesla said:
A far better way, however, to obtain power would be to avail ourselves of the sun’s rays, which beat the earth incessantly and supply energy at a maximum rate of over four million horsepower per square mile. Although the average energy received per square mile in any locality during the year is only a small fraction of that amount, yet an inexhaustible source of power would be opened up by the discovery of some efficient method of utilizing the energy of the rays.2
While they both recognized the potential for renewable energy, they could not have foreseen the success of distributed solar PV, let alone advances in energy storage or the expanded role consumers would play in this idyllic future.
Nearly 100 years after Tesla and Edison made these prognostications, the utility industry is facing perhaps the most significant transition since the two energy pioneers debated the virtues and pitfalls of alternating versus direct current. Driven by climate change policies, advances in technology, significant cost reductions, and the emergence of the prosumer—as discussed in companion chapters in this volume—states like California, Hawaii, New York, and a host of others are forced to recognize and begin planning for significant growth potential for distributed energy resources.
Like the divisive Edison/Tesla debate over how best to transmit electricity, today there are clear divisions among the various stakeholder groups about what the future of the utility industry should look like. Given the great deal of uncertainty surrounding the future role of utilities and the resulting impact on their financial well-being, utilities are trying to protect their vested interests while at the same time complying with regulatory mandates and state policy imperatives.
DER providers are also trying to carve out a profitable niche in the burgeoning prosumer energy space and create innovative products and services to differentiate themselves from one another and from utilities. Yet these same providers view utilities as potential customers and are caught between advocating on behalf of consumers and fostering good relationships with utilities.
Prosumer motives vary from a desire for energy independence from utilities, to a commitment to addressing environmental and climate change challenges, to strong interest in clean energy and technologies, or a desire to realize economic benefits DER may provide. Generally speaking, their interests focus on benefits they accrue rather than supporting the reliable and cost-effective operation of the grid, in part because they have no visibility into, and likely little interest in a macroview of utility operations. To the degree there are financial incentives, programs, or mechanisms made available, they may participate in supporting distribution grid operations. Aggregators and service providers are the likely vehicle for residential and small business consumers for participating in distribution services, while larger commercial, industrial, or agricultural customers may choose to participate individually.
Finally, regulators must try to balance these diverse and often divergent interests, all while looking out for disadvantaged customers and those customers who have little desire to change their relationship with utility providers. Aside from installing PV on their roof or buying an electric vehicle (EV), many consumers are, at this stage, likely unaware of DER options available to them now or in the near future, such as the potential role they play as prosumers or the impact their energy choices have on grid planning, operations, and ultimately the financial health of utilities.
Section 2 of this chapter looks at the various stakeholder interests and drivers of DER. Section 3 provides a high-level comparison of the approaches to planning for DER in California and New York. Section 4 is an in-depth look at the foundational steps necessary to bring about a transition to grid-edge technologies. Section 5 provides an overview of the current regulatory framework and how it must change to support a future with significant amounts of DER, followed by the chapter’s conclusions.
2. Challenges and opportunities of high levels of DER
For the most part, DER exists today under a patchwork of disparate utility programs, nurtured by public policies and regulations focused on avoiding large capital investments, keeping rates low or in response to customer demands. Programs have varied widely from state to state and utility to utility, depending on regional grid needs or policy goals.
For example, California has one of the most successful energy efficiency programs in the country, holding average residential energy consumption steady for decades, as well as the largest rooftop solar PV programs in the nation, along with a growing base of EVs—largely a result of state policies and regulations. Similar variations are seen in other parts of the world, as described in other chapters of this book.
On the other hand, demand response programs have been relatively weak and piecemeal in the Golden State. In comparison, demand response programs have been more successful and prolific in the East and Northeast. The common thread has been for regulators and utilities to treat these resources separately via special tariffs or programs as adjuncts to conventional grid resources.
However, as DER adoption grows, regulators are beginning to realize that the future of planning and investment is in fact largely driven by what happens at the grid’s edge, namely the intersection of the distribution network and customers’ premises. One need only look at states with high solar PV penetration levels, such as Hawaii (Box 9.1), to see the impact of not planning for DER.
Spurred by more aggressive public policy goals aimed at mitigating the impacts of climate change as in California3 and Hawaii,4 or in response to resiliency concerns postnatural disaster in the case of New York,5 some regulators and utilities are beginning to view DER as collective resources to support the grid and allow customers more control over their energy choices. In large part, these policies have helped accelerate the decline in prices for technologies like solar PV, resulting in rapid consumer uptake of behind-the-meter solar.
There are several drivers spurring the current evolution of DER:
• Public Policy Goals
• Utility/Grid Needs
• Market Forces
These drivers, described below, and their respective constituencies, often have conflicting motives and needs. As acknowledged in the introductory and concluding statements in this volume by leading regulators from Australia, California, New York, and Europe, the challenge regulators and policymakers now face is how to align these drivers to create value for all market participants. As will be discussed later, a major barrier to achieving this objective is the current regulatory and financial framework that has existed for the past 100 years or longer.
2.1. Public Policy Drivers
Regulated utilities have always been subject to public policy priorities. As evidence, one must only look at the litany of utility rates and tariffs, which may include rates for low-income customers, economic development, direct access, community choice aggregation, green energy, distributed generation, and a host of other policy-inspired fees, charges, and tariffs. Specific rate components are often used to fund energy commissions or generic public benefits programs. In the case of DER, more and more utility commissions are seeing the potential opportunity to avoid greenhouse gas emitting resources or even traditional capital investment in the grid.
2.2. Utility/Grid Needs Drivers
DER presents both challenges and opportunities for distribution utilities. Smart inverters, whether associated with PV, stationary storage, or even EVs, can provide voltage regulation, volt-VAR optimization, frequency response, and a host of other services. Energy storage is seen as a potential source for fast-ramping to address the diurnal profile of solar PV, and along with EVs, can absorb excess energy at times of high solar production, reducing or eliminating overgeneration issues in spring or fall months. Solar PV provides midday energy and capacity, which can help defer capacity upgrades on the distribution and even transmission grid. Particularly when combined in optimized portfolios, DER can be strategically deployed in a manner that enhances grid reliability and at lower costs than traditional utility capital investments.
Deploying DER, from a utility perspective however, is challenging and complex. Most distribution grids were designed for one-way power flow under a utility command and control structure. And while utilities have had little control over energy consumption outside of tariffs and demand-side management programs, the growing popularity of solar PV and EVs and the potential for consumer-oriented energy storage technologies makes managing the grid far more uncertain and complex.
These concerns have been highlighted by the tremendous success of the California Solar Initiative (CSI) program along with the State’s aggressive Renewable Portfolio Standard (RPS). As of the fourth quarter of 2016, the CSI program has resulted in 1813 megawatts (MW) of installed behind-the-meter solar PV, with another 126 MW in application.6 Through the end of 2015, California had a total of 5498 MW of installed in-state central station solar PV, plus an additional 1292 MW of solar thermal generation7—largely a result of the State’s aggressive RPS policies. The growth in solar has changed the net load profile for the state so much that daytime solar production at times now exceeds demand, resulting in negative prices for solar energy in the California Independent System Operator’s (CAISO) markets. CAISO has estimated that, absent operational changes and other mitigations, this situation will continue to worsen, as illustrated in the now-infamous “California duck curve” (Fig. 9.1).
Figure 9.1 CAISO “duck curve.” (Source: Licensed without endorsement with permission from the CAISO.)
On the distribution grid, the success of behind-the-meter solar PV could significantly increase bidirectional energy flows on the grid, impacting the operation of protection devices, possibly increasing wear and tear on equipment, such as voltage regulators. Some of these impacts can be mitigated or avoided using intelligent inverters deployed with PV and energy storage, while some may require grid modernization upgrades. The degree to which such upgrades are necessary, and which can be avoided via intelligent deployment of DER that support grid operations, is the subject of significant debate.
As will be discussed in Section 5 of this chapter, utilities, and in particular investor-owned utilities (IOUs) have a vested interest in remaining viable and continuing to generate value for their shareholders. Under the current regulatory construct, utilities can’t earn value for shareholders from third-party or customer-owned DER as they can from traditional grid infrastructure capital investments. The widespread deployment of DER within their borders is an existential threat to these utilities, as significant capital investment in both resources and infrastructure shift from utilities to the grid edge—all the way to the customer or prosumer premises.
Regulators are also interested in making sure utilities remain viable so they can serve vulnerable customer segments and those consumers who simply want to remain full-service utility customers. The challenge for regulators is balancing the needs of a diverse group of stakeholders with sometimes diametrically opposing priorities and needs. A particularly vexing problem is determining a new role for utilities and a regulatory framework that both supports traditional consumers, prosumers, third-party DER technology and service providers, the utilities themselves, and their shareholders.
2.3. Market Drivers
What’s unique about DER is the degree to which market forces are driving technological adoption. To be sure, technological advances and significant price declines have driven consumer adoption of lighting, space conditioning, and appliances since the very early days of electric utilities. Most of those advances, however, resulted in increased energy consumption as a result of automation and improvements in consumer comfort and convenience. Consumers were, and largely remain passive takers of utility services and subject to the utility ratemaking framework.
The current crop of DER, which includes distributed generation, energy storage, and EVs—further covered in other chapters—not only serve customer needs, but also have the ability to support grid operations. Solar energy provides consumers with the option to reduce their carbon footprint while reducing energy costs and acting as a hedge against future rate increases. The current crop of energy storage is largely aimed at arbitraging demand charges, with a segment of residential customers viewing it as a way to avoid consumption of fossil generation. Enabled by the Internet of Things—devices connected to the Internet and controllable via computers and smartphones, consumers have more control over how and when they consume or even produce energy. The newly empowered prosumer has emerged, requiring utilities and regulators to rethink the traditional utility–consumer paradigm.
Importantly, third-party owned distributed resources have the potential to significantly lower energy sales and displace traditional utility grid investments. While energy efficiency and other demand-side management programs have been a staple of utility offerings since the first energy crisis in the early 1970s, they have had a relatively minor impact on utility revenue and profits. Often regulators have put in place performance-based or earnings adjustment mechanisms to offset lost sales from energy efficiency program requirements.
Prudency reviews have ensured, or attempted to ensure, utility investments are necessary, just, and reasonable, avoiding overinvestment in the grid and helping keep rates more affordable for consumers. While not a perfect system, the regulatory compact has ensured monopoly utilities have the ability to earn a guaranteed, fair rate of return for their shareholders or owners, while providing a strong measure of protection for consumers against unreasonably high rates.8
Regulators must try to implement public policy goals while balancing the needs of consumers and utilities. In the past, this has mainly focused on reducing customers’ energy use and bills and avoiding unnecessary grid investments by the utilities. However, with the challenges presented by climate change and the policies enacted to mitigate these impacts, along with incentives and the rapid decline in prices for solar PV and EVs and the increasing availability and affordability of DER, balancing these needs has become more difficult.
3. California and New York—a tale of two regulatory approaches
California and New York are the two highest profile examples in the United States for addressing DER planning and deployment. Both recognize the potential benefits and challenges DER presents and have begun to develop regulations to facilitate the transition to a more decentralized future.
New York began with a vision for reinventing the utility sector, an effort they called Reforming the Energy Vision (REV). The vision laid out a new role for utilities as Distribution System Platform Providers (DSPPs). These DSPPs are responsible for optimizing the distribution system utilizing DER as well as providing aggregated energy and ancillary services to the bulk system operator. The New York Public Service Commission (NYPSC) views the accurate pricing of DER as essential to achieving these objectives.
The ultimate objective of the NY REV process is to create a market where DER owners or aggregators are able to offer services into a distribution level market, much like wholesale markets operated by Independent System Operators (ISOs) or Regional Transmission Operators (RTOs), such as the New York ISO (NYISO) and CAISO. In addition to bilateral transactions, these markets offer day-ahead and hour-ahead energy markets, ancillary services markets, and sometimes capacity markets. By establishing a distribution services market, the NYPSC hopes to achieve efficiencies inherent in market structures and create opportunities to monetize the wider range of attributes DER can provide.
In contrast, California’s approach has focused more on the technical aspects of identifying ideal locations for DER and determining the locational net benefits rather then developing market mechanisms to accelerate deployment of DER. The focus is largely on deferring capital investments at specific locations on the grid rather than addressing autonomous DER growth driven by consumer needs. Sourcing has focused on competitive procurement by the utilities based on granular locational net benefits rather than creating market structures to address these needs.
Unlike New York, California has thus far avoided the issue of identifying a new structure or role for utilities. In late 2016, the California Public Utilities Commission (CPUC) did issue a decision that created a pilot utility incentive mechanisms that address, at least in part, the issue of compensating utilities for procuring third-party DER rather than making traditional capital investments, which under the current regulatory framework earn value for their shareholders.9 Aside from this limited incentive pilot program, however, the CPUC has yet to consider changes to the regulatory framework, such as the creation of market mechanisms or the formation of a distribution system operator structure.
Thus the focus in California is more on building the foundation for a modern grid via creating the modeling, data, processes, and regulations that identify optimal locations and locational net benefits, rather than addressing the evolution of the utility’s role and the regulatory and economic framework necessary to sustain DER growth. That’s not to say California regulators and policymakers are not aware of the need to address these important issues, but rather the focus has been more short-term and pragmatic, emphasizing building the foundational components that are necessary for an eventual market structure and regulatory framework.
To varying degrees, California utilities are generally ahead of utilities in New York from the standpoint of deploying advanced grid analytics and planning, and in particular smart meter technologies. Access to detailed subhourly load data and system data should give utilities in California the ability to be more precise in determining highly granular locational net benefits for DER. However, lacking a longer term vision for how this data might inform more accurate and efficient sourcing mechanisms and identifying the role utilities and consumers will each play in a future distributed grid has caused a misalignment between the IOUs’ financial interests and State policy goals driving DER deployment.
Concerns about this misalignment have surfaced in other proceedings, including IOU general rate cases and EV infrastructure deployment proposals. Parties to the proceedings have raised concerns about overinvestment in grid infrastructure, or “gold-plating” the grid by utilities to compensate for lost opportunities to rate base capital investments that could be deferred or avoided via procurement of third-party DER. Utilities have countered that the investments in grid infrastructure are necessary for integrating DER and maintaining reliability, but the questions surrounding the future role of utilities and their compensation structure have created uncertainty and calls for increased scrutiny of utility spending.
4. Getting the most out of DER
Deploying significant amounts of DER while maintaining reliable grid operations requires a significantly higher level of situational and operational awareness and planning. Data, from consumption/production by consumers to highly granular locational grid conditions and even current and forecasted weather conditions, are foundational to successfully operating a grid with high levels of DER penetration. In this section, I will describe how California is addressing these data needs in the near term, as well as future data considerations.
4.1. Need for Granular Geographical and Temporal Data
In the past, DER included mainly utility energy efficiency and demand response programs along with a smattering of customer-owned combined heat and power systems or on-site generation. Each resource was treated separately via tariffs, programs, or bilateral agreements, but generally speaking was optimized to meet bulk power system needs or accommodate customer needs. With the dramatic increase in distributed solar PV, growth in customer demand for EVs, and early interest in distributed energy storage, the trend in DER is shifting much more toward meeting customer wants with less regard for impact on the grid.
At low levels of penetration, utilities can manage DER integration via the interconnection process. However, as DER becomes more and more prevalent, utilities will have a much more difficult time managing the grid and meeting customer expectations. Since DER can be deployed throughout the distribution grid, utilities need to understand loads and system conditions at a highly granular level, both geographically and temporally.
PG&E, for example, has modeled the DER integration capacity, or hosting capacity, of over 3,000 circuits, with over 102,000 line segments and 500,000 nodes.10 In addition, they have installed roughly 5 million smart meters that collect subhourly load data on electric customers in their service territory. They have modeled all of their three-phase line segments, but have not yet modeled the single-phase line segments, which comprise roughly one-third of their total circuit miles and which are mainly radial lines serving residential customers.
Modeling the single-phase line segments would increase precision, and is ultimately needed for determining distribution marginal costs for eventual distribution markets and for matching detailed customer load data with operational data for the line segment on which the customer is interconnected. The California utilities do have plans to evaluate the single-phase line segments to determine hosting capacity, which will provide more granular cost data to inform future procurement and sourcing options and markets.
Rather than reacting to DER deployed solely to meet customer needs, utilities are attempting to leverage advanced distribution planning tools to identify where DER can provide the greatest benefits to the grid and which attributes and combinations of DER can provide the greatest value to the grid. Secondarily, understanding locational conditions and needs better enables utilities to understand how to support customer-driven DER by designing programs or incentives to mitigate any potential negative grid impacts such deployment might cause. Since not all customers who install DER will be interested or able to provide grid services, it’s important to understand where and in what quantities this DER growth may occur and mitigate the impacts to the extent possible.
For example, if a customer located on a circuit that has little available capacity wanted to purchase one or more EVs, the utility could either charge the customer a fee to upgrade the circuit to accommodate this new load, or instead offer them programs or incentives to make energy efficiency improvements, install rooftop solar or energy storage, or participate in a demand response program to avoid making costly system upgrades. Particularly in areas where there are GHG reduction, air quality improvement or customer choice policies driving DER deployment, it is important to understand and mitigate costly upgrades that would otherwise make DER less economic to customers.
4.2. Customer Load and Demographic Data
Utilities around the country have installed, or are in the process of installing advanced “smart meters” throughout their service territory in an effort to reduce operational costs, improve metering/billing accuracy and grid reliability, and eventually enable customers to respond to signals to better manage their usage and allow the utility to better manage the grid. Obtaining subhourly customer load data from these smart meters is an important first step in understanding current usage patterns and predicting potential future patterns.
Forward-thinking utilities are now using forecasting models that include economic and weather data to forecast loads at the subcircuit level. This highly granular analysis enables the utility to better understand not only usage trends, but also DER growth potential and output. These data are essential for determining the locational value of DER and designing sourcing mechanisms to deploy DER in a manner that supports the efficient and reliable operation of the grid.
Historical and forecast weather data are necessary not only for understanding and predicting heating, cooling, and lighting loads, but also for predicting solar PV output. Larger utility service territories may cover a wide range of climatological and geographical conditions, increasing the importance of locational forecasting.
For example, PG&E’s service territory in California covers cool coastal regions where air conditioning is less common, to the much warmer Central Valley, and into the Sierra Mountains. Even within the San Francisco Bay Area, where the company is headquartered, temperatures can vary by as much as 25–30°F from the coast to the inland valleys. Understanding weather impacts on loads historically and in near-real time at the subcircuit level enables utilities to understand what the grid needs are and which forms of DER and in which combinations can best meet those needs.
4.3. Hosting Capacity Analysis
The first step in determining the value of DER is to identify the optimal locations where they can provide the greatest benefits to the grid. Using data collected from smart meters and other sensors on the grid, along with the load, economic, and forecasting data described previously, utilities perform an analysis of the circuit DER hosting capacity, sometimes referred to as an Integration Capacity Analysis (ICA).11 This is done using a power flow analysis that is performed for each circuit using data representing load profiles, weather conditions, DER operational profiles, seasons, and other factors. The analysis is used to predict the available unused capacity along each circuit, showing how much additional DER can be accommodated on the circuit.
Utilities in California then publish this information in graphical form using geographic information systems “heat maps.”12 Circuits with ample available hosting capacity are colored green, ones with more constraints are yellow, while highly constrained circuits are depicted in red. Although details in early versions of the maps vary from one utility to the next, clicking on the circuit on the map brings up information, such as circuit voltage, capacity, projected peak load, and existing and planned distributed generation megawatts.13 This information allows DER project developers to identify locations where capacity exists to install more solar PV or other DER.
Fig. 9.2 shows a screenshot from PG&E’s ICA map14 for a portion of Oakland, California. Clicking on one of the line segments in the map brings up information on the circuit, shown in Fig. 9.3.
Figure 9.2 Sample Pacific Gas and Electric Company Integration Capacity Analysis (ICA) map.
Figure 9.3 Sample Pacific Gas and Electric Company ICA circuit data.
Once the utilities complete the analysis on all of their circuits, more detailed information is expected to be included. This will include the timing, duration, and nature of the constraint that exists, such as a thermal overload, power quality or voltage violation, protective device conflict, or safety and reliability issue. These more detailed maps will provide valuable tools for third parties to identify high priority areas to target for DER development. The additional data describing the specific constraints will help them tailor their solutions to meet specific grid needs. This type of targeted deployment, tailored to meet specific grid needs, helps grid operators maximize the benefits of DER for all customers while keeping costs low.
4.4. Locational Net Benefits Analysis
While the ICA identifies locations on the grid where constraints exist and includes criterion of what may be causing the constraint, the Locational Net Benefits Analysis (LNBA) attempts to determine the value for DER at specific locations along the grid. In simple terms, the LNBA is an accounting of the difference between the benefits and costs of integrating DER at specific locations on the distribution grid.
California Public Utilities Code Chapter 4, Article 3, Section 769 establishes the requirement for utilities to evaluate locational benefits of DER:
Evaluate locational benefits and costs of distributed resources located on the distribution system. This evaluation shall be based on reductions or increases in local generation capacity needs, avoided or increased investments in distribution infrastructure, safety benefits, reliability benefits, and any other savings the distributed resources provide to the electrical grid or costs to ratepayers of the electrical corporation.15
To understand the benefits of DER, the utilities first identified the potential value components. These include the more obvious benefits, such as avoided distribution capacity, avoided line losses, ancillary services, increased reliability and resiliency, along with societal benefits, greenhouse gas reduction, and renewable energy integration benefits. Table 9.1 shows the various components from PG&E’s Distribution Resources Plan that are used to determine locational net benefits.
Table 9.1
Consolidated Components For PG&E’s Locational Impact Analysis
| # | Component | PG&E definition |
| 1 | Subtransmission, substation, and feeder capital and operating expenditures (distribution capacity) | Avoided or increased costs incurred to increase capacity on subtransmission, substation, and/or distribution feeders to ensure system can accommodate forecast load growth |
| 2 | Distribution voltage and power quality capital and operating expenditures | Avoided or increased costs incurred to ensure power delivered is within required operating specifications (i.e., voltage, fluctuations, etc.) |
| 3 | Distribution reliability and resiliency capital and operating expenditures | Avoided or increased costs incurred to proactively prevent, mitigate, and respond to routine outages (reliability) and major outages (resiliency) |
| 4 | Transmission capital and operating expenditures | Avoided or increased costs incurred to increase capacity on transmission line and/or substations to ensure system can accommodate forecast load growth |
| 5a | System or local area RA | Avoided or increased costs incurred to procure RA capacity to meet system or CAISO-identified LCR |
| 5b | Flexible RA | Avoided or increased costs incurred to procure flexible RA capacity |
| 6a | Generation energy and GHG | Avoided or increased costs incurred to procure electrical energy and associated cost of GHG emissions on behalf of utility customers |
| 6b | Energy losses | Avoided or increased costs to deliver procured electrical energy to utility customers due to losses on the T&D system |
| 6c | Ancillary services | Avoided or increased costs to procure ancillary services on behalf of utility customers |
| 6d | RPS | Avoided or increased costs incurred to procure RPS eligible energy on behalf of utility customers as required to meet the utility’s RPS requirements |
| 7 | Renewables integration costs | Avoided or increased generation-related costs not already captured under other components (e.g., ancillary services and flexible RA capacity) associated with integrating variable renewable resources |
| 8 | Any societal avoided costs which can be clearly linked to the deployment of DERs | Decreased or increased costs to the public which do not have any nexus to utility costs or rates |
| 9 | Any avoided public safety costs which can be clearly linked to the deployment of DERs | Decreased or increased safety-related costs which are not captured in any other component |
Source: Pacific Gas and Electric Company’s Electric Distribution Resources Plan, July 1, 2015, Table 2-12, p. 65.
LCR, Local capacity requirement; RPS, Renewable Portfolio Standard.
The California Public Utilities Commission directed the State’s IOUs to use an avoided cost calculator, modified to capture distribution system impacts, as the basis for determining the avoided costs on which the locational benefits are to be derived.16 The calculator was originally developed for evaluating system level avoided costs, but has been modified to accommodate distribution level impacts.
To maximize the net benefits for all customers, it is essential to get as complete and accurate accounting as possible of the benefits and costs of DER at specific locations along the grid. This includes the value to not only the distribution system, but also to the bulk grid and to customers, both with and without DER. Utilities, such as PG&E have the ability to identify highly granular data—from customer smart meters and potentially intelligent inverters, to grid conditions and historical data at the three-phase, and soon single-phase circuit levels, to very locational weather and demographic historical and forecast data. This will enable very accurate evaluation of the locational net benefits, assuming the utilities include all of the appropriate value components mentioned previously.
There is one very important additional consideration, however. To realize the full value DER can provide, utilities must evaluate optimal combinations, or portfolios, of DER. For example, rooftop solar alone may provide capacity value and potentially voltage or frequency support. But a rooftop PV system that combines energy storage and/or an EV can provide ramping support, avoid overgeneration at times of peak solar production and low loads, or help stabilize the grid in other ways. Therefore, utilities should consider the potential impact and value of DER portfolios instead of or in addition to individual DER. This step is also important for developing appropriate incentives and sourcing mechanisms to influence the design and deployment of third-party DER.
4.5. DER Sourcing
Understanding the more precise value of DER is essential for creating new sourcing options and for transitioning from current, cruder methods of compensating DER, including Net Energy Metering tariffs. At low levels of penetration that now exist in most jurisdictions, NEM is an important tool for encouraging distributed PV, helping such technologies to achieve greater economies of scale. It also works quite well for most utilities today given the general lack of sophisticated grid analysis tools and data.
However, as distributed PV reaches higher levels of penetration and other forms of DER become more widely available, and as utilities deploy advanced grid analysis and planning tools, more precise, locationally and temporally, granular values of DER are necessary for cost-effectively deploying DER. To facilitate the transition from more crude sourcing options and incentives requires a more complete accounting of the full value DER can provide.
Most utility sourcing today is done through pricing (via rates, tariffs, and incentives), programs (such as mandatory levels of energy efficiency or RPS requirements), and procurement. As was previously mentioned, each distributed resource type is typically treated in siloed fashion for pricing and programmatic sourcing options. The same is generally true for procurement, where the utility issues a Request for Offers (RFO) for a specific resource type and megawatt level to meet an identified need at a specific point in time.
What’s lacking in the sourcing mix in California is a transition to market-based sourcing structures. The NY REV process specifically identifies markets as the end-state goal of the process, though data and analytics have not yet been developed sufficiently to support such mechanisms. The DSPP framework established by the NYPSC changes the role of the utilities to one that supports and enables markets to operate efficiently and effectively.
California’s approach of relying on Purchased Power Agreements (PPAs) instead of transitioning to markets places greater emphasis on contingency planning—what to do if the DER fails to materialize in the quantities and at the times needed, if at all. While penalties for nonperformance can be incorporated into PPAs between utilities and DER providers, this does little to address very real reliability concerns. The typical fallback if the DER fails to show up at all is for the utility to go forward with grid upgrades that would have otherwise been built, or to screen and restrict DER providers to a narrow list of “preferred providers” that could hinder competition and technological innovation.
By their very nature, markets create opportunities for multiple suppliers to compete and encourage innovation by providing price transparency. This of course assumes timely, accurate, and detailed data is accessible to all market participants in a manner that enables bidding of optimal resource attributes to meet the identified needs.
From a pragmatic standpoint, however, markets may take longer to develop and require careful thought to protect against gaming the system. Enron’s actions in California during the deregulated era at the beginning of the century highlight the potential dangers of poorly designed markets and lax oversight. Given the significant potential disruption to the utilities’ operational and financial modus operandi, it may make sense to start with more familiar sourcing mechanisms, such as RFOs for distribution investment deferral, tariffs, and programs, modified to incorporate data from the ICA and LNBA evaluations.
One example of a more conventional tariff structure that could support DER deployment is an options payment tariff for voltage support. Much like a demand response tariff, where customers who agree to reduce load when called upon during critical peak periods are paid a monthly fee, and then are compensated for any actual demand reduction they make in response to the utility’s signal. In the case of DER like solar PV with smart inverters or energy storage, the DER customer would be paid an options fee that allows the utility to activate voltage regulation capabilities of the inverter. The customer would also be compensated for the actual voltage support provided, as metered by the inverter or a utility meter, to compensate for the reduced energy output of the inverter.
The steps both New York and California are taking to identify hosting or integration capacity, optimal locations, and to identify and assign precise locational values for DER are of course fundamental to creating more effective sourcing mechanisms, whether they be tariffs, programs, competitive solicitations, or market mechanisms. A planned approach that incorporates several sourcing mechanisms while building toward a market structure will likely prove most successful.
5. Aligning utility financial motives with DER policy goals
A fundamental barrier standing in the way of widespread DER deployment is the existing regulatory framework and IOU revenue structure that has existed for over a 100 years. Most utilities earn a guaranteed rate of return that is calculated on a combination of their energy sales and capital investments, although in some states earnings have been “decoupled” from sales.
In California, an example of a decoupled regulatory framework, IOUs, earn a rate of return that is largely based on the depreciated value of approved capital assets. This gives the utilities an inherent bias toward owning assets rather than procuring services via PPAs. Yet DER is typically owned by customers or third parties, creating a misalignment between the utilities financial interests and the policy objectives enacted by the state with regard to DER. As a result, there exists a situation where utilities are being asked to defer capital investments, on which they would otherwise earn a rate of return, and instead procure third-party owned DER, which provides no value to shareholders. The Commission has attempted to address this in the short term via DER incentive pilot programs, but has left open the larger question of what role the utilities will play and how will they earn value for their shareholders as more and more DER are deployed throughout the grid.
This situation creates an additional regulatory burden to ensure utilities don’t overinvest in grid upgrades, correctly value the benefits DER can provide, or delay the deployment of advanced grid planning tools and data platforms in an effort to forestall DER deployment. This presents regulators with a difficult task during the early stages of transitioning to the grid of the future, as utilities submit annual distribution plans and begin a new cycle of general rate cases.
Regulators must ensure capital investments support higher levels of customer and third-party owned DER and be wary of approving traditional investments in the distribution grid that may later become stranded or which foreclose opportunities for deploying DER. Utility commissions may lack the technical expertise to evaluate whether a specific utility investment could be deferred or displaced by DER, or fully understand the capabilities and limitations of DER as alternatives to traditional grid investments.
Smart inverters, for example, can provide many of the voltage regulation capabilities that might otherwise require utilities to install capacitors or other equipment to control voltage. Substation, transformer, or conductor upgrades, unless done to replace aging unreliable equipment, could be deferred with the addition of DER in the right locations. Even some of the communications and control equipment that utilities are considering to allow them to directly control dispatching of DER could be duplicative of the inherent capabilities DER possesses.
If utilities overinvest in the grid, questions arise about who should pay for these investments—shareholders, all utility customers, or just those customers who’ve installed DER. Regulators must be very careful in balancing the interests of vulnerable customers, those who choose not to participate as prosumers, and those who do. Allocating grid modernization costs to non-DER customers will elicit complaints about one group of customers subsidizing another group of customers. Conversely, burdening DER customers with stranded cost recovery will likely result in higher fixed costs, negating some or much of the economic benefits of DER and having a chilling effect on DER deployment. Yet burdening shareholders with the costs of potential stranded investments, which were approved in regulatory proceedings, is also unfair.
Regulators must therefore carefully evaluate all utility infrastructure requests and determine whether the investments are truly necessary to support the reliable and cost-effective operation of the grid, or whether they could be deferred or displaced with well-placed and well-designed portfolios of DER. It is therefore imperative that regulators create the proper incentives, motivations, and regulatory framework for utilities to consider DER as alternatives to traditional grid investments without concern for the impact on their financial well-being.
6. Conclusions
The utility world has changed dramatically since the time of Edison and Tesla, yet in many regards the utility industry remains largely familiar to the time when alternating current and direct current were first being debated. But an industry that fueled the second industrial revolution cannot remain immune for long from the advances it helped spawn. Technological advances in solar power, energy storage, vehicle propulsion, communication systems, and data processing and analytics have converged to produce a new world of distributed energy resources to complement the Internet of Things. These resources are empowering a new breed of prosumers, who have the ability to control how and when they use, generate, or even store electrical energy, fundamentally changing their relationship with utilities that once served as their sole provider of electric service. In this Darwinian world, utilities and regulators must also adapt to meet the evolving demands and desires of consumers, or face extinction like species and industries of the past.
Fortunately, states like California and New York are blazing new trails for others to follow. New York, with its strong vision of the future and focus on building a new role for utilities and driving toward distribution markets, has created a degree of regulatory certainty that allows each party to focus on their respective role. California’s more pragmatic approach, with its focus on planning tools, data, modeling, and analysis, is establishing the fundamentals and building a solid foundation upon which DER technology and service providers, markets, and sourcing options will be built. Though neither approach is without its flaws, regulators in other jurisdictions can take the best approaches from each state to use as a template upon which to build a framework best suited for their situation.
Regulators must recognize the needs and drivers of the various stakeholder groups to understand how to create a framework to support DER growth in a way that balances these varied and sometimes conflicting interests. They must continue to protect vulnerable customers and those that choose not to participate in this new energy future, ensuring that the grid operates reliably and that rates remain reasonable and fair for all customers. They must recognize the inherent conflict that exists between the existing utility financial structure and newly enacted public policy goals that could potentially erode shareholder value. Most importantly, regulators must create a clear vision for the future of the grid and establish some measure of regulatory certainty. Ultimately, each of the participants in this new energy paradigm—utilities, DER technology and service providers, prosumers and traditional utility consumers—must succeed in order for this new framework to succeed. It’s imperative that regulators show strong leadership to help bring this about in the most efficient, cost-effective, and reliable manner possible.
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