by Seth H. Handy, Handy Law LLC
Rhode Island laments its high cost of electricity for good reason; it is not competitive. Few fully understand what drives that cost. It is commonly presumed that the expense is driven by the cost of supply; but, that is only a piece of the puzzle. Supply actually accounts for forty percent of the residential rate while transmission and distribution (T&D) – moving electricity across large regional wires and then through the smaller wires in our community – makes up forty eight percent of that rate. For a long time, T&D hid behind the scenes with the utility simply reporting on what it cost to provide that service and getting its return on that investment. More recently, with leadership from the RI Office of Energy Resources, the Public Utilities Commission, the Division of Public Utilities and Carriers and our Governor, our State has worked collaboratively to identify and take advantage of the opportunity for cost savings on the provision of T&D services.
In the Rhode Island Public Utility Commission’s docket 4568, National Grid responded to the general assembly’s invitation to consider the impacts of distributed generation on our energy system by proposing that renewable energy projects pay a fee for use of the distribution system. They justified that fee on the ground that distributed energy resources put costs on the system that result in subsidization by other customers and that the proposed fee would “contribute towards the support for the distribution system” and “ongoing operation, maintenance and replacement costs.” Opponents raised National Grid’s failure to weigh the costs and benefits that distributed energy resources provide to those customers and the system, as mandated by the statute, before concluding they are a cost driver. National Grid responded:
DG [distributed generation of renewable energy] has the potential to provide capacity relief in local areas having distribution system constraints. Therefore, any compensation for the benefits that DG might bring to the Company and its customers is specific to the condition that is causing the constraint and the time over which distribution system investment can be deferred. As part of the RE Growth Program annual filing requirement in 2016, the Company will be evaluating the use of localized credits in 2016 for location where DG would be helpful. . . however, although there are potential benefits of DG, there is also a cost that DG imposes by virtue of connecting to the system.
In Docket 4568, the Company resisted the concept of value and the process of real valuation, submitting that any benefits were purely local and constrained, should only be compensated through incentive programs, and were not generally relevant to its rate proposals. In the face of strong and uniform opposition, National Grid ultimately withdrew that proposal for an access fee. The Commission then initiated a new docket to help it prepare for a real valuation process.
In Docket 4600, the Public Utilities Commission retained a consultant and organized a group of stakeholders to implement a value-based approach to all energy policies and programs where we deliberately seek to maximize benefit and minimize cost. The stakeholders included National Grid, the Energy Council of Rhode Island (representing large commercial and industrial energy users) and the George Wiley Center (representing low-income interests), among others. With the help of the invaluable expertise of Karl Rábago of the Pace Energy and Climate Center, our firm represented a coalition of nine businesses and the Rhode Island League of Cities and Towns. After fifteen months of stakeholder proceedings coordinated by an expert consulting firm, RAAB Associates, Ltd., the group unanimously stood behind a final report that makes a series of findings and recommendations.
That consensus report sets Rhode Island on a new path to pursue value for the benefit of Rhode Island ratepayers and citizens. The first step was to identify the categories benefits and costs that could be realized. While historical regulatory processes had focused exclusively on minimizing direct costs and benefits to ratepaying customers, Docket 4600 produced agreement that any accurate valuation process must also consider any input’s costs and benefits (value) to the power system and to society.
The report does identify five categories of costs and benefits to the customer: prosumer benefits (activating the customer), non-energy impacts (e.g., value of energy use avoided through efficiency improvements), low-income benefits, consumer empowerment and choice benefits, and non-participant rate and bill impacts. All such impacts are important and are better understood than the other categories of agreed impacts and, therefore, are not the subject of this article.
In contrast, the report identifies twenty impacts at the “power system level” – costs and benefits on the transmission and distribution system – that are not so well understood but are the drivers for 60% of our electric bill, the transmission and distribution component. I will first list them and then highlight examples of why they are important.
- Energy supply and transmission operating value of energy provided or saved
- Renewable energy credit cost/value
- Retail supplier risk premium
- Forward commitment: capacity value
- Forward commitment: avoided ancillary services value
- Utility/third party developer renewable, energy efficiency or DER costs
- Electric transmission capacity costs/value
- Electric transmission infrastructure costs for site specific resources
- Net risks/benefits to utility system operation (e.g., adaptability, diversification & reliability)
- Option value of individual resources
- Investment under uncertainty – real options cost/value
- Energy demand reduction induced price effect
- Greenhouse gas compliance costs
- Criteria pollutant and other environmental compliance costs
- Innovation and learning by doing
- Distribution delivery costs
- Distribution system performance
- Utility low-income
- Distribution system and customer reliability/resilience impacts
- Distribution system safety loss/gain
The stakeholders agreed that energy system inputs, whether they be investments in new transmission lines or legislative mandates for efficiency, can have a wide range of impacts on our power system. Some of those impacts are easier for a layperson to understand than others. Frankly, having been through many stakeholder meetings, I can admit that some of them still challenge my technical capacity. Thankfully, I have confidence in the many experts engaged in our deliberation process and am ready to rely on (and benefit from) all their diligence. In the end, it will be worth our effort to understand all impacts because they are interesting and they shape our energy system. Here we have space to briefly look deeper into just five of them.
Forward commitment and capacity value is an important one. The entity that controls our regional electric grid (the “Independent System Operator” or “ISO”) manages the wholesale electric markets throughout our region. They have to be sure we have adequate supply to meet our electrical needs throughout the region. That is not an easy job. They ensure it is done well not only by constant competitive bidding but also by paying generators to guaranty that their supply will be available for periods of time in the future. That is the way they can ensure not only that supply and demand are in balance today but also that it will be in balance tomorrow and for days that come. The process of determining how much energy will need to be secured in the future and how much they should pay for commitments on that supply involves complex projections that are effected by a wide range of variables. One important variable is the implementation of distributed energy resources like energy efficiency and renewables, because they can reduce the need for regionally committed supply and thereby abate the cost of capacity payments for all the region’s consumers.
Electric transmission capacity costs/value are a somewhat related factor. The process of getting regionally supplied forward capacity commitments also requires ISO to evaluate whether they have the means to deliver that supply to their customers. “Transmission” is a term of art used in this industry to describe the infrastructure (generally large towers and electrical lines or large underground conduit and wires) needed to move electricity (often at high voltage for long distances) from a large supply source to one or more local distribution systems (lower voltage and shorter distances on smaller poles and wires). If the ISO intends to rely on large-scale regional supply sources, it must authorize investments in transmission improvements to enable conveyance of such supply, which investments come at significant cost to all benefitting customers. Private investment in local distributed energy resources (DER) can avoid the need for those transmission system investments.
“Distribution capacity cost” involves similar kinds of analyses, but at the distribution system level. Our local utilities manage those systems and are under regulatory requirements to ensure that their local system has adequate capacity to serve their customers. Local DER can mitigate or even eliminate the need for distribution system enhancements, thereby saving cost to customers. It is also possible that large renewable energy projects sited in rural locations with inadequate distribution infrastructure could increase cost to the distribution system, although such costs have historically been funded by the private developer of the system. Legislation proposed in the 2015, 2016 and 2017 Rhode Island general assembly would require private developers to fund such improvements unless the improvements benefit other customers. How the costs of such needed system improvements should be funded moving forward is only one element of what should be a more comprehensive analysis of the total costs of such local renewable energy systems. That analysis will differ based on the system’s condition and capacity and load requirements in a specific location.
Impact on environmental compliance costs bears explanation because it is commonly misunderstood. Here, the analysis does not intend to address immeasurable impacts such as effects on climate change. The environmental compliance cost to the power system is as concrete as the water towers built at the Brayton Point power plant in Somerset, Massachusetts. Those cooling towers were required by EPA to cool the water discharged from that power plant before it was discharged to Mount Hope Bay. That the requirement came, in significant part, out of concerns for the impact that the discharge temperature was increasing the temperature of the bay enough to kill off the winter flounder population. The cost of that compliance obligation was real and substantial and was ultimately funded by rate-paying electric customers, including many Rhode Island customers that were sourced from that plant. There is no question that generating sources operate under environmental laws and regulations that can clearly and definitively result in compliance costs. DERs like efficiency and renewables can avoid the need for such investments.
Finally, the category “Innovation and Learn by Doing” is too catchy to pass without some comment. Here, the stakeholders agreed that there is some intrinsic value to trying new things out in order to see whether they might benefit the system. As one commentator puts it:
Innovation thrives in a competitive environment; it’s an indulgent luxury in a regulated monopoly… Technological innovation is an evolutionary process, a discovery process with outcomes that no one can fully anticipate. Thus, if we want to learn what, if any, of these digital energy innovations people find valuable, experimentation is crucial. This evolutionary process is the real reason market competition creates value: decentralized markets are simply processes of learning, discovery, and error correction. As they evolve, markets create system-wide efficiencies and outcomes that are otherwise impossible if centrally planned.
Surely that “value” of innovation involves both costs and benefits, like the cost of deployment and the potential benefit of having tested something that does have significant potential to bring down the cost of our energy delivery system. One deployment example is the Aquidneck Island System Reliability pilot where Rhode Island’s office of energy resources and National Grid are overseeing a planned process of trying to implement DERs to avoid the need for a specific distribution system investment that would otherwise be required in that service location. That pilot comes at a cost, but its benefit is to demonstrate the specifics of how to plan and orchestrate private investments to avoid the cost of otherwise necessary system improvements. The potential for savings from that pilot is not its only benefit; it also may prove the specifics of a case that can then be transferred and applied elsewhere. Similarly, the pilot currently underway to prove whether streetlight meters and control mechanisms can be effective and properly integrated into National Grid’s billing system not only has the potential to benefit the system directly and in many ways (e.g., enhanced controls over efficiency and incentive for cost savings) but also may pave the way for broader implementation across the service territory.
We can now see and understand a bit more about the specifics of how investment decisions impact not only customers but also the power system as a whole. It is also worth noting that the stakeholders also agreed on the importance of identifying yet a third category of costs and benefits to analyze in association with energy policy investments and decisions – impact on society. It includes: greenhouse gas externality costs (e.g., climate), criteria air pollutant and other environmental externality costs, conservation and community benefits, non-energy costs/benefits (e.g., economic development), innovation and knowledge spillover (bolstering our knowledge center), societal low-income impacts, public health and national security and U.S. international influence. There is not ample space to get into these factors here, but they are also fascinating and warrant further explication and understanding. The experts have acknowledged their consequence and Rhode Island will consider them in its future energy decisions.
Rhode Island learned a whole lot from a great range of experts and stakeholders representing every possible interest in our energy economy through the discourse in Commission Docket 4600. We have yet to reap many of the rewards of that work, but there is now a framework for analysis that will produce much better value from our energy decisions moving forward. One thing is clear and certain, those who do not seek value do not find it.
 See Basic Residential Rates for Delivery Service, https://www9.nationalgridus.com/narragansett/home/rates/4_a16.asp (Distribution 27.4%, Transmission 20.4%) and Summary of Rates Standard Offer Service – https://www9.nationalgridus.com/non_html/rate_summary_2096.pdf (supply 40%).
 For PUC Docket 4568 see http://www.ripuc.org/eventsactions/docket/4568page.html; for the legislative mandate, see R.I. General Laws §39-26.6-24.
 Testimony of Peter T. Zschokke and Jeanne A. Lloyd (“NGrid Testmony”) at page 62. Reply to PUC data request 1-18.
 See e.g., Testmony of Karl R. Rábago for Wind Energy Development, at p. 15.
 NGrid Testmony, p. 39.
 C. Wilson-Frias, RIPUC Deputy Chief of Legal Services, “Request for Comments on a Docket to Investigate the Changing Distribution System” (Feb. 5, 2016); C. Wilson-Frias & T.Bianco, “Recommendations for a Docket to Investigate the Changing Distribution System” (March 1, 2016).
 Docket 4600, Final Report Exh. B, Section ____.
 An Act Relating to Public Utilities & Carriers, H5483/S637 (2017 Session).
 “EPA and MA DEP Issue New Draft Permit to Reduce Environmental Damage to Mount Hope Bay from Brayton Point Power Plant,” Environmental Protection Agency (July 22, 2002) – https://yosemite.epa.gov/opa/admpress.nsf/6d651d23f5a91b768525735900400c28/350c2ad3e01ed983852573f3007d3222!OpenDocument.
 L. Kiesling & D. Munson, “A Revolution in Power: Where We’ve Come From, Where We’re Headed,” Electricity Policy, (Sept. 2016), pp. 3, 8.
 Peregrine Energy Group, Inc, “Solar PV for Distribution Grid Support: The Rhode Island System Reliability Procurement Solar Distributed Generation Pilot Project” (June 30, 2014) – http://www.energy.ri.gov/documents/SRP/RI-SRP-PV_Report_Peregrine-team_07-16-2014.pdf.