By Mike O’Boyle
Regulators have a utility information problem. People who want to see a cleaner electricity system know it well. As both the identifiers of and profiteers from new infrastructure needs, utilities have embedded incentives to identify solutions that involve utility-owned infrastructure. Regulators have insufficient information to compare utility proposals against alternatives, and so the litigious, adversarial nature of utility ratemaking continues to lag behind technological potential for a cleaner, cheaper, more reliable grid.
In a May 2016 Trending Topics piece, we wrote that regulators can pursue either outcome-oriented or information-intensive approaches to solving the utility information problem, and get the most out of clean, distributed energy resources (DERs). We urged experimentation with both approaches, concluding that in an era of ever-increasing options for power system optimization and ever-rising information asymmetry, regulators will have to find ways to improve outcomes through a combination of utility incentives and improved data access. (see also our submission to the Smart Electric Power Alliance 51st State Initiative on this subject)
Two years later, experimentation is happening and solutions are emerging, albeit relatively slowly. Integrated distribution planning (IDP) is an information-intensive solution being tested in at least 11 states.
Meanwhile performance-based regulation is being explored or implemented in at least 12 states (in many cases concurrently with IDP) as a way to motivate utilities toward system optimization.
Six states are testing both approaches at once, and combining the two approaches may make great sense if the aim is to move a slow-moving system a bit more quickly. And in Washington D.C., a new model has emerged as a possibility – vesting the authority for data sharing and distribution system optimization into a public third-party entity.
What we’re getting from Integrated Distribution Planning
Studies consistently confirm there is massive potential for cost-effective demand-side participation, including rooftop solar PV, storage, demand response, energy efficiency, and managed vehicle charging. For example, Rocky Mountain Institute’s recent report The Economics of Clean Energy Portfolios shows the system-wide potential for portfolios of DERs and clean energy resources to replace natural gas power plants, improving affordability, reliability, and environmental performance. A recent analysis from LBNL showing efficiency is the cheapest resource available, rigorous studies of the value of solar, National Renewable Energy Laboratory’s 2025 California Demand Response Potential Study, and numerous state-level cost-benefit analyses of utility EE and DR programs further support the potential for demand-side participation to reduce system costs.
A few states have already had success operationalizing DERs as system resources, even before going through a full IDP process. Examples include successful non-wires alternatives (NWA) demonstration projects in New York and California, including a recent decision to permit Pacific Gas & Electric to procure storage and DERs to replace uneconomic gas resources.
Even with what seems like overwhelming evidence showing these resources provide benefits, in specific instances regulators, stakeholders, and even utilities can’t tell whether and to what extent they should be a part of utility system planning. Environmental and consumer advocates cry out for cheaper, cleaner options to be included, but lack the information necessary to rebut specific utility proposals. This happens in integrated resource plans, grid modernization plans, and utility rate cases.
Integrated distribution planning (IDP) is uncovering information essential to incorporating demand-side resources into utility planning. IDP in California and New York has revealed system needs such as local generation and substation upgrades that can be met with a combination of conventional resources and DER. Calls to undertake hosting capacity analysis have resulted in improved distributed generation connection times in California and Hawaii, but the full potential for demand-side resources and more comprehensive NWAs to become part of grid planning still eludes even DER vanguard-states.
Efforts to organize and release publicly available data are essential to realizing an affordable, reliable, clean electric grid. These data illuminate the potential and value of dynamic load, storage, and other resources to balance the variability of inexpensive solar and wind on daily and instantaneous timescales.
But a more fundamental question is emerging out of this information: Who should process, manage, and share all this data, and who should administer competitive solicitations for NWAs? The tension was apparent in a recent Utility Dive article covering the Interstate Renewable Energy Council’s Guide for State Regulators on Hosting Capacity Analyses. In the article, utility and Electric Power Research Institute representatives argued that mandates to share system capacity for DERs in real-time are premature, while DER advocates argued that policymakers need to take bold steps and move quickly.
Given the underlying incentives that virtually punish utilities for collaborating with DER providers, the old question of utility incentives and information needs comes up again in the context of IDP itself: Given the incentives at play, can utilities really do IDP well?
An outcome-oriented approach for integrated distribution planning
Under the conventional approach to IDP (if we can yet say there is a conventional approach), utilities are required to do a lot of things they never did before:
- Quantify and reveal DER hosting capacity
- Quantify and reveal system needs before investing in solutions,
- Anticipate DER deployment and incorporate into other planning exercises
- Communicate the data more or less in real-time
- Create a means for customers to share their energy demand data to DER providers
- Solicit proposals from DER providers to aggregate customers and provide grid services
Utilities are infrastructure companies with less experience in information and data management, meaning they may need to develop new internal capabilities to meet these demands. But cost of service regulation provides no upside for this kind of innovation. In fact, the more successful a utility is at integrated distribution system planning, the more likely they are to defer or displace the need for utility-owned infrastructure. Under cost of service regulation, that winning proposition for ratepayers is actually a losing proposition for utility investors.
Without changing the utility’s business model and its financial incentives at the front end, the chances of a successful IDP at the back end are pretty slim.
Performance-based regulation can align utility incentives to ensure they will become more profitable if they roll-out IDP in a way that maximizes system and customer benefits. In particular, putting capital expenditures on equal footing with operational expenditures is an important nut to crack. Utility Earnings in a Service-Oriented World by Advanced Energy Economy Institute highlights the opportunities and challenges of equalizing solutions that require utility CapEx versus utility OpEx.
For example, in New York’s DER alternative demonstration projects, the utilities can place expenses for DER contracts into regulatory asset accounts, meaning they can earn a regulated rate of return on certain operational expenses. This is accompanied by a shared savings mechanism that allows the utility to make additional profits that scale with the size of the savings relative to the conventional solution. This approach is being tried in Rhode Island as well, and explored in Hawaii, California, and Minnesota.
States are also exploring performance incentive mechanisms (PIMs) that reward the utility for improving system efficiency and reducing cost. New York, Massachusetts, and Rhode Island utilities earn extra returns when they reduce system peak demand; this targeted incentive approach is being explored further in Minnesota, Oregon, and Hawaii.
Getting these incentives right could motivate utilities to get the most out of DERs, even when it means investing less capital in their systems.
A new information-intensive approach – outsourcing IDP
One approach to solving the potential conflict of interest that a utility might have in conducting integrated distribution planning is to hand responsibility to a third party. The Distributed Energy Resources Authority Act (DERA Act) being debated at the D.C. Council would vest authority for IDP with a non-utility nonprofit entity called a DER Authority. The proposal is an information-intensive approach to system optimization; it requires the utility to share unprecedented data about its system needs and customer usage in real-time, and relies on a new entity to synthesize this data to procure DERs.
It’s worth noting this model of outsourcing functions that antagonize the existing utility business isn’t new; energy efficiency utilities such as Efficiency Vermont, Energy Trust of Oregon, and Hawaii Energy are effective nonprofit entities that administer public efficiency budgets to maximize energy savings. And even these entities’ mandates are no longer limited to efficiency. Efficiency Vermont and Hawaii Energy have targets for peak demand reduction as well, while the Energy Trust of Oregon helps customers adopt small-scale renewable energy projects; perhaps a sign that the D.C. proposal is not as radical as it seems.
Under the DERA Act, the DER Authority takes over many of the functions the utility would typically do under IDP, including:
- Creating forecasts of system load and DER deployment that feed into utility resource planning
- Analyzing DER alternatives to utility infrastructure investments over $25m and soliciting bids from DER providers
- Standardizing distributed smart inverter data to share with the DER authority
- Creating recommendations for changes to rate design and other programs that could accelerate cost-effective DER deployment
- Creating a customer-facing website and platform to connect customers with DER providers
Even with the creation of this new authority, the utility’s role in optimizing DERs would still be significant. The utility is required to supply public information in real-time about its hosting capacity for DERs on every circuit, as well as its larger-scale infrastructure needs, defined by the services they provide – e.g. capacity, energy, voltage support – giving the utility significant control over what becomes a NWA candidate. The utility will also have to provide the DER Authority with real-time data about customer usage at the meter level and ensure smart meters can communicate easily with in-home devices. These are new functions the utility is likely unprepared for today, and so it may need new revenue and potentially performance incentives or investment opportunities as carrots to accomplish these tasks.
From a public policy perspective, the D.C. proposal has several merits. First and foremost, it creates (or endeavors to create) an entity with a clear directive, resources, and incentives to maximize DER deployment comprehensively for the public good. It solves aspects of the utility information problem by requiring the utility to provide massive amounts of crucial information necessary to identify the highest-value opportunities for DERs. It also provides a pathway to develop the market for elusive DERs, particularly demand flexibility, which can complement variable low-cost generation without increasing environmental impacts.
But the proposal may still struggle to live up to its intention. As an extremely detailed legislative proposal, the bill is proscriptive but also may leave unforeseeable loopholes that regulators may find challenging to counteract. For example, the requirement that utilities define system needs and share them with the DER Authority for a request for proposals for DER alternatives are vague. Left unspecified are the specific capabilities that must be defined and replaced, though the bill does create a stakeholder process to resolve many unspecified details.
Also, the requirement that these needs must meet a $25m threshold to be subject to NWA analysis means that utilities can break infrastructure proposals into components that fall under this threshold. And it does not solve the underlying information incentive problem – without a change to the underlying business model of the utilities, which here would be excluded from profiting off of the optimization of DERs, there are few reasons to play ball.
The DER Authority is a new experiment in the information-intensive approach to promoting system optimization. Equally important are reform combinations that increase regulatory focus on rewarding utility outcomes. Other states should watch carefully, particularly those who are frustrated with the utility’s willingness to proactively engage customers and embrace cost-effective DERs.