In August, we published a list of the top 10 utility regulation trends of 2019 — so far. With 2019 wrapping up, we check in again. Ten trends and actions stand out above the rest, from states implementing 100% clean energy targets, to distributed energy resource integration efforts, to beneficial electrification investments. Here is the full round-up of the top matters before PUCs in 2019.

Note: some links in this post reference PUC filings and other documents in AEE's software platform, PowerSuite. Click here and sign up for a free trial.

As renewable energy and energy storage resources have become increasingly cost-competitive (see more in #2), states have become more and more ambitious in their clean energy targets. In fact, at least 13 states plus Puerto Rico and D.C., have now set 100% clean energy targets. A few others, including Illinois, Maryland, Michigan, and Oregon, have announced initial plans to transition to 100% clean energy. In addition, at least six investor-owned utilities — Avista, Duke Energy, Green Mountain Power, Idaho Power, Public Service Co. of New Mexico, and Xcel Energy — operating in 12 other states have committed to 100% clean energy targets of their own. While the requirements, timelines, and implementation mechanisms may differ, one trend is clear — there’s nothing alternative about advanced energy anymore.

In January, Washington, D.C., codified the most aggressive target, setting 2032 as the deadline for powering its grid with 100% renewable energy. Throughout the rest of 2019, eight other states and Puerto Rico followed suit. Most notably New York, which in July set a 70% renewable energy requirement by 2030 and a 100% carbon-free resource requirement by 2040. Several of these states have already begun moving toward implementation. 

In June, the Public Utilities Commission of Nevada opened a rulemaking to implement SB 358 (passed in April), which increases the state's renewable portfolio standard (RPS) to 50% by 2030, with a goal of reaching 100% clean energy by 2050. 

In July, the New Mexico Public Regulation Commission initiated a docket to implement legislative direction set by SB 489 (also known as the Energy Transition Act, passed in March) to accelerate advanced energy adoption, facilitate economic development, and leverage innovative finance (primarily via securitization of retiring coal-fired power plants) to transition the state's power system to 100% clean energy by 2045. 

Also in July, the Washington Utilities and Transportation Commission initiated a rulemaking to organize the implementation of advanced energy legislation that passed in 2019, including the Clean Energy Transformation Act (SB 5116), to transition the state's electricity sector to 100% carbon-free by 2045. The Maine Public Utilities Commission also opened a rulemaking in July to implement LD 1494 and its new renewable resource portfolio requirement of 80% by 2030 and 100% by 2050.

The continued price decline for renewables and storage in 2019 is making it more cost-effective to achieve many of the ambitious clean energy targets outlined above. In fact, in most states, it is now often cheaper to build new wind and solar plants (in some cases even when paired with storage) than to operate existing fossil-fuel power plants. The data bears this out. The average levelized cost of energy for large-scale solar PV and onshore wind without subsidies is now as low as $32 and $28 per MWh respectively. This compares favorably to the marginal cost of operating existing coal plants — now at about $33 per MWh. Falling costs have led to an estimated $2.6 trillion in new investments in clean energy, as defined by Bloomberg New Energy Finance, in the past decade. Renewables are now dominating utility long-term resource plans.

To kick off 2019, the New Mexico Public Regulation Commission approved Public Service Co. of New Mexico’s (PNM) latest integrated resource plan (IRP), which calls for the retirement of all coal-fired generation in its portfolio by 2031.

In Michigan, DTE Electric Co. and Consumers Energy Co. both proposed plans to phase out coal by 2040. In March, DTE proposed 11 MW of solar-plus-storage projects and 693 MW of wind projects over the next five years, followed by 525 MW of solar between 2025 and 2030 and another 2 GW by 2040. In June, the Public Service Commission approved Consumers’ plan, which calls for 5 GW of new solar by 2030 and a 90% reduction in carbon emissions by 2040.

In April, Public Service Co. of Colorado received approval for the construction of a $743 million, 500 MW wind farm (representing about 8% of its peak summer demand), which the utility aims to bring into commercial operation by the end of 2020, to take advantage of the full value of the federal production tax credit. This represents only a small piece of the power company’s expected energy transition over the next couple of decades, with the goal of achieving 100% carbon-neutral generation by 2050.

In April, Northern Indiana Public Service Co (NIPSCO) filed a petition for a $21 million annual electric revenue increase premised on its most recent integrated resource plan, which proposes to retire all coal in its fleet by 2028 and replace it with a portfolio of solar, storage, wind, and demand management. NIPSCO stated that its plan is expected to save customers $4 billion over the next 30 years.  

In June, Georgia Power reached a settlement agreement in its 2019 Integrated Resource Plan that calls for the retirement of close to 1 GW of coal generating capacity and the procurement of 1.5 GW of renewable resources and 150 MW of distributed generation resources. This plan marks the continued steep decline in Georgia Power’s emissions in recent years, driven by plant economics, as these planned retirements are in addition to 3.1 GW of already retired coal plants — representing about 20% of its existing peak load.

In October, PacifiCorp in Utah filed its 2019 integrated resource plan, with a preferred portfolio that includes accelerated coal retirements and the addition of over 6,400 MW of new renewable resources, 600 MW of battery storage capacity (all co-located with new solar resources), and over 700 MW of incremental energy efficiency and new direct load control resources by the end of 2023. 

In November, the California Public Utilities Commission issued a proposed reference system plan (RSP) that utilities and other load-serving entities will use to inform their individual resource plans that are due in May 2020. The default case in the proposed plan calls for almost 3 GW of new wind, 12 GW of solar, 11 GW of battery storage, and about 200 MW of “shed” demand response by 2030. (Shed demand response is what is traditionally thought of as demand response where loads can be curtailed in peak capacity events.)

Renewable energy is also gaining traction in Mississippi. At the beginning of the year, Entergy Mississippi filed an application for a $138 million, 100 MW solar facility. Entergy said it is pursuing the solar facility because of increasing customer interest and recent reductions in solar costs. If approved, it would be the first large-scale, utility-owned solar project constructed in Mississippi. And in November, Mississippi finalized a new holistic integrated resource planning process that requires utilities to consider demand-side and distributed energy resources on an equal footing with traditional supply-side resources. 

Traditional cost-of-service regulation favors utility capital investment in long-lived assets rather than rewarding utilities for their performance against desired policy objectives. As utilities grapple with a changing energy landscape, many state public utility commissions have started to look at performance metrics and incentives to spur utility innovation in meeting policy goals.

In January, the Minnesota Public Utilities Commission finalized Phase 1 in its performance-based regulation (PBR) investigation for the state’s largest utility — Xcel Energy. The Commission kicked off Phase 2 in March, to develop metrics for the performance outcomes established in Phase 1 – affordability, reliability, customer service quality, environmental performance, and cost-effectively aligning generation to load. In September, the Commission subsequently established these five performance metrics and provided guiding principles for developing metrics to ensure flexibility, technology neutrality, and outcome-driven methodology design. And in October, Xcel proposed specific methodologies for each of these metrics that are currently under consideration. 

In January, New York’s Con Edison filed a petition to increase its annual electric and gas delivery revenues. A key component of the rate case was expected to be the implementation of earnings adjustment mechanisms — New York’s version of performance incentive mechanisms — coming out of the Reforming the Energy Vision (REV) initiative. In a comment letter on the settlement proposal now pending in the rate case, Advanced Energy Economy Institute raised concerns about EAMs being too heavily tied to program performance, rather than outcomes, thereby doing little to spur utility innovation: “[EAMs] were appropriately intended by the Commission to provide meaningful financial incentives for utilities to pursue innovative solutions to meeting state policy objectives. Several years later, EAM implementation continues to fall short of the original intent.”

In May, the Public Utilities Commission of Hawaii concluded Phase 1 of its investigation to develop a new PBR framework by identifying 12 key outcomes and a portfolio of priority PBR mechanisms for updating Hawaii's regulatory design. The Decision also established the guiding principles and objectives for Phase 2 to include: (1) setting a revenue target to optimize near-term customer savings; (2) enhancing customer engagement; (3) improving DER performance; (4) streamlining utility performance; and (5) re-aligning financial incentives with societal outcomes (e.g., GHG reductions, transportation electrification, resilience). Phase 2 formally began in August and will run through 2020 with a focus on revenue adjustment mechanisms and performance mechanisms. The Aloha state has also been working to level the playing field for certain power-purchase agreements (PPAs) to accelerate the procurement of low-cost renewable energy.

In July, the Public Utilities Commission of Nevada opened a rulemaking to implement Senate Bill 300 (passed in 2019), which directs state regulators to explore an alternative ratemaking process — including performance incentives, decoupling mechanisms, and earnings-sharing mechanisms — that aligns utility business models with meeting the state's 100% clean energy statute. After a couple of rounds of comments and workshops that laid out preliminary goals and outcomes for alternative ratemaking, the Commission is expected to delve into the details in 2020. 

In July, the Pennsylvania Public Utilities Commission issued a final policy statement concluding a multi-year stakeholder process that outlines 14 factors the Commission intends to consider when evaluating distribution utility alternative ratemaking proposals. Some of the factors include: 1) cost causation; 2) fixed utilities capacity utilization; 3) interclass, intraclass cost-shifting; 4) promotion of efficiency programs; and 5) how the proposed mechanism interacts with other revenue streams. 

The Colorado Public Utilities Commission will also soon be engaged in re-thinking utility regulation with the passage of SB 236, the Public Utility Commission Sunset bill signed into law in May. Among other things, the bill requires the Commission to study the impacts of performance-based metrics to better understand and identify mechanisms that would encourage the state’s utilities to make investment decisions that benefit the public good, increase energy savings, and improve safety and reliability. The bill also authorizes the creation of a ratepayer-backed bonding mechanism (securitization) to expedite the closure of outmoded power plants as the state transitions to cleaner, more economic resources.

Electric vehicle (EV) charging infrastructure and EV integration have continued to dominate the conversation in front of many state public utility commissions, as improvements in technology and model offerings have dramatically expanded the EV market. In fact, as shown in the graph below, EVs will soon be at purchase price parity with traditional internal combustion vehicles (they are already at lifetime cost parity when accounting for lower maintenance and fuel costs). Actions have included statewide foundational EV investigations, widespread infrastructure deployments, and a range of demonstration projects.

California continues to lead on transportation electrification (TE), with 46% of the nation’s electric car sales originating in the Golden State. At the turn of the year, the California Public Utilities Commission initiated a rulemaking to provide more structure and guidance on future TE investments and to streamline the application process. Under California’s existing construct, all utility applications have been considered on a case-by-case basis, which has led to a prolonged review process and unfocused investment strategy. This new process, referred to as the DRIVE OIR, seeks to develop a TE framework that will help to strategically integrate TE load; enhance market coordination of utility investments; enable private sector investments; achieve policy cohesiveness on key issues (i.e., rate design, consumer education, and vehicle-grid integration policy); and evaluate cost-effectiveness of investments and different ownership and cost recovery models. A staff proposal for a TE framework is expected to be issued before the end of the year.

In January, the Public Service Commission of Wisconsin opened an investigation to consider policies and regulations in regards to EVs and their associated supply infrastructure in Wisconsin. The Commission is expected to hold the first in a series of workshops in December to facilitate further education and dialogue on EV issues in the state. 

In February, the Missouri Public Service Commission opened a proceeding to evaluate potential mechanisms for utility involvement in EV charging stations. The process culminated in a Staff Report that laid out key themes identified throughout the process, including 1) any action by the Commission should allow for flexibility, 2) any action should be technology-neutral to the greatest extent possible, 3) robust data collection, and the eventual use of that data, are key to successful deployment, 4) enhanced customer education is a must, and 5) approval of pilot programs may be the best path for Commission involvement.

In February, the New York Public Service Commission issued an order approving a proposed incentive program to encourage the deployment of public direct current fast charging (DCFC) stations. The consensus proposal – which was jointly filed by the state's utilities, the New York Power Authority, the Department of Environmental Conservation, the Department of Transportation, the New York State Thruway Authority, and the New York State Energy Research and Development Authority (NYSERDA) – will provide $31.6 million in incentives for over 1,000 publicly accessible DCFC charging stations. Specifically, each utility will offer an annual per-plug incentive that will decline over time as electric vehicle usage, and thus DCFC utilization, increases.

In April, the Oregon Public Utilities Commission adopted rules requiring electric utilities to file for Commission acceptance of TE plans every two years that lay out their long-term strategy to accelerate TE in their service territory. In October, Portland General Electric Company filed its first plan, followed by Idaho Power in November. PacifiCorp is expected to file its TE plan in February 2020.  

Also in April, the Iowa Utilities Board finalized a Notice of Intended Action (formally adopted as a rule in September) that removes EV charging stations from the definition of a public utility and affirmatively states that the charging of an EV does not constitute the resale of electric service. This ruling is key to the viability of the business model for third party charging companies as it allows them to set their own rates for the use of their charging stations. 

In June, the Nevada Public Utilities Commission opened a proceeding to implement Senate Bill 299 (passed in 2019), which revises laws related to the state’s EV Infrastructure Demonstration program, which provides school districts with funds for electric school buses and charging infrastructure.

In June, the Vermont Public Utility Commission submitted a report to the state legislature recommending the removal of barriers to the adoption of EVs, including more EV purchase incentives, easier pathways for the installation of public charging infrastructure, and increased education and outreach. 

The Arizona Corporation Commission has also been in the thick of developing an EV policy implementation plan. A policy implementation plan that was issued in July provides guidelines for utilities to propose EV pilot programs focused on structure, education and outreach, make-ready, rate design, incentives/rebates, and cost recovery, and also requires utilities to jointly develop a long-term, comprehensive transportation electrification plan, for review and approval by the end of the year. 

In October, the Colorado Public Utilities Commission opened a proceeding to implement Senate Bill 77, passed in 2019, that directs utilities to file applications for TE programs. The Commission is collecting stakeholder input to provide guidance for utilities’ TE applications in advance of the first filings, which are due in May 2020. 

There has been no shortage of activity across the country, with utility proposals or statewide investigations in D.C., Delaware, Hawaii, Iowa, Maryland, Michigan (DTE Electric and Consumers Energy), Minnesota (Minnesota Power, Otter Tail Power, and Xcel Energy),  North Carolina, South Carolina (Duke Energy Progress and Duke Energy Carolinas), and Texas. 

In 2019, an increasing number of utilities and regulators have been considering how DERs can be more fully integrated into the electric power system. Optimizing DER interconnection processes and making investments in the distribution grid that unlock the multiple value streams that DERs can provide, will enhance the customer experience and lead to a more flexible and cost-effective grid. In addition, and often overlooked, are the reliability and resiliency benefits, which are of increasing importance as the intensity and occurrence of severe weather events persist. Needless to say, the distribution grid is the backbone of a reliable electric system, and utilities are investing accordingly. 

In February, New Hampshire Public Utilities Commission staff issued a report with a recommended approach for utilities to assess their distribution systems, conduct least-cost distribution planning strategies, and incorporate grid modernization initiatives. The Commission has subsequently held a series of technical sessions to further determine a path forward. 

In March, the Arkansas Public Service Commission kicked off a long-awaited DER and grid modernization investigation. The first phase has been focused on informing stakeholders on the existing state of the grid, including aging distribution infrastructure, the role of data in a modern grid, and the impact of DER on utility planning and operation. In a parallel effort in September, the Commission also opened a proceeding to streamline interconnection requests of net-metering facilities and access to renewable DERs. 

In May, Indiana Michigan Power took the first step towards a modern grid by filing an application in Indiana as part of a larger general rate case asking for full smart meter deployment by 2022. In September, Virginia Electric Power (aka Dominion) filed its second petition (see the first petition here that included $154 million in investments) for approval of its Grid Transformation Plan (GTM). The largest utility in Virginia requested approval for $593.5 million in investments for the first three years of its 10-year plan. The GTM plan focuses on six components: 1) a full six-year advanced metering infrastructure deployment, 2) a new customer information platform, 3) grid improvements, which include grid technologies and grid hardening, 4) telecommunications infrastructure, 5) cybersecurity, and 6) an EV smart-charging infrastructure pilot program.

In October, the Michigan Public Service Commission established the MI Power Grid initiative — a focused, multi-year stakeholder initiative intended to maximize the benefits of the transition to clean, distributed energy resources for Michigan residents and businesses. Also in October, 

the Public Utility Regulatory Authority in Connecticut issued an interim decision in its distribution system planning investigation that details a near-term and long-term framework to further investigate methods for grid modernization. And in November, the Arizona Corporation Commission adopted distributed generation interconnection rules for utilities to use when considering applications for interconnection and parallel operation of distributed generation facilities. 

Energy efficiency has undergone significant changes in response to developments in technologies, markets, and public policies, but states are continuing to see its value. Energy efficiency is most commonly thought of as reducing energy use by replacing traditional technologies with new ones, such as LED lighting and high-efficiency appliances and heating and cooling equipment. But today, energy efficiency can be accomplished, and its value derived, through a variety of means, including the use of sophisticated energy management systems, internet-connected thermostats, and data analytics. The growing differential between average and peak demand has also led some states to rethink the value of demand-side management at different times of the day.  

In January, Florida established a docket to review its utility's conservation goals. Under the Florida Energy Efficiency and Conservation Act of 1980 (FEECA), the Florida Public Service Commission must revisit each of seven utilities' electricity and peak demand savings targets at least once every five years. While energy efficiency goals have traditionally been modest in Florida, compared with many states, in this cycle, four out of the state’s seven utilities subject to FEECA proposed goals of close to zero. However, in a relative win for energy efficiency, the PSC in November rejected the utilities’ proposed goals and instead voted to keep the current goals established in 2014, however modest, in place through 2025. 

By contrast, traditional efficiency leader California has continued its efforts to expand its programs in 2019. In January, the California Public Utilities Commission initiated a rulemaking to enhance its ongoing efforts to reduce greenhouse gas emissions associated with buildings, consistent with the state’s goals of reducing economy-wide GHG emissions 40% below 1990 levels by 2030 and achieving carbon neutrality by 2045 or sooner. Progress has also been made, albeit slowly, in Phase III of California’s energy efficiency proceeding to meet the doubling of energy efficiency by 2030 targets as set out in 2015’s SB 350. Phase III is focused on revisions to the three-prong fuel substitution test (with a final decision issued in August) (i.e., a requirement that a program must pass to be considered eligible for energy efficiency funding incentives), and market transformation programs to achieve deeper energy efficiency savings. In August, the Commission issued a ruling on a draft revised rulebook for normalized metered energy consumption (NMEC) (i.e., a data-driven approach to measuring the effectiveness of energy efficiency investments, often referred to as M&V 2.0. See here for details.) In October, the Commission issued a proposed decision (PD) adopting frameworks for regional energy networks and market transformation initiatives. The PD, which will likely be voted on by the Commission before the end of the year, also proposed maintaining the Market Transformation Working Group to work through unresolved issues. 

In Ohio, on the other hand, the near term future for energy efficiency looks bleak. In July, the legislature passed HB6, which essentially scrapped the state’s energy efficiency resource standard. (See here for details.) A key part of the legislation is a requirement that prohibits the Public Utility Commission from approving cost recovery for programs after the utilities meet their existing targets (which utilities are already are on the cusp of achieving). As a follow-on to that legislation, the Public Utilities Commission of Ohio asked for input in October on whether it is appropriate for electric utilities to continue ratepayer-funded energy efficiency programs after the statutory cap of 17.5% of cumulative energy savings since 2009 has been met. 

On a more positive note, in March, New Mexico signed HB 291, which raised the bar for energy efficiency programs by setting energy savings requirements of no less than 5% of 2020 sales by 2025. In addition, the Legislation also authorizes the use of decoupling, which reduces the utility disincentive to investing in energy efficiency by eliminating the link between sales and revenues. In May, the Maine Public Utilities Commission approved over $158 million in energy efficiency funding — about $37 million per year for electric utilities and $325,000 per year for natural gas utilities for Efficiency Maine Trust’s 2020-2022 fourth triennial plan (the remaining budget will go towards innovation, public information, administration, and evaluation, measurement, and verification). 

In June, the Arkansas Public Service Commission approved six of the seven utilities' 2020-2022 energy efficiency plans submitted in March, which will implement the Commission’s new energy target of 1.2% (of 2018 retail sales) savings targets for 2020 to 2022 for electric utilities.

In August, the Nevada Public Utility Commission wrapped up its multi-year effort to implement  AB 223, which authorized the Commission to accept energy efficiency plans if they are deemed cost-effective (including both economic and societal benefits) and 5% of funds for energy efficiency programs are directed toward low-income customers. 

For decades, net energy metering (NEM) has been successful in spurring the adoption of distributed generation across the country, with Minnesota the first state to adopt a NEM law in 1983. However, as the penetration of distributed generation increases, most notably rooftop solar, pressure has been building to develop an alternative way to value the costs and benefits of distributed generation. In 2019, several states have taken various approaches to successor tariffs to NEM, ranging from straight reductions in net metering rates for exported electricity to the development of granular methodologies for determining the value of distributed generation on the grid. 

In February, the New Hampshire Public Utilities Commission initiated a study of the locational value of distributed generation to evaluate alternative designs and methodologies. The first technical session with Navigant Consulting, which was chosen to conduct the study, was held in October. 

In April, Idaho Power filed a petition to suspend net metering service and explore modifications to the compensation structure for customer-owned generation facilities with capacity up to 100 kW, even though existing net metered capacity represents just 0.15% of the utility’s summer peak demand of 3,400 MW. Idaho Power expressed concern that capacity under its net metering tariff had increased 114% in the first quarter of 2019 alone, driven by large commercial, industrial, and irrigation customers, with capacity from irrigation alone jumping from 1.09 MW to 5.06 MW. No decision has been made to date, but if the Public Utilities Commission sides with the utility, it could nip Idaho distributed generation in the bud.

On a more positive note, New York made some landmark adjustments that should provide fairer treatment for customers that have significant distributed generation facilities. In April, the Commission issued an order that made revisions to the state’s DER value calculation and compensation methodology, and also adopted a new credit to encourage community distributed generation development. And in May, the Commission issued an order modifying the current standby and buyback service rates that will improve the alignment between system costs and how DER customers make use of the grid, which should ultimately improve the prospects for DER deployment. (A more detailed look at this order is available here.)

In June, the Connecticut Department of Energy and Environmental Protection and the Public Utilities Regulatory Authority opened a joint proceeding to study the value of DER, as required by Public Act 19-35. The agencies are expected to submit a report on their findings to the General Assembly by July 2020. Also in June, the Kentucky Public Service Commission opened a proceeding to implement SB 100, which changes the way electric utility customers receive credit for the electricity they generate, by requiring the Commission to set a value for DERs rather than rely on traditional net metering. 

In September, the Louisiana Public Service Commission adopted a revised net metering policy that repeals the 0.5% cap on current solar users but also reduces compensation for excess energy sold to the utility from the retail rate to avoided cost. The revised net-metering rules establish a 15-year grandfathering provision (i.e., through 2034) for solar customers who install distributed generation by the end of this year. 

In December, the Maine Public Utilities Commission issued a final rule to implement changes to the net energy billing (NEB) rules necessitated by 2019 legislation. Key parts include 1) the expansion of facilities eligible for the NEB program from a maximum capacity of 660 kW to 5 MW; and 2) the replacement of the existing requirement of ownership with a “financial interest” standard (i.e., broadening the eligibility of customers who can participate in NEB to include arrangements such as a lease or a power purchase agreement); and 3) the creation of a new "commercial and institutional” NEB rate.

Looking ahead, the California Public Utilities Commission is expected to open a new rulemaking by the end of the year to develop a long-term successor NEM tariff — or as it will be referred to in California, NEM 3.0. 

In January,  the largest investor-owned utility in California — Pacific Gas & Electric (PG&E) — filed for Chapter 11 bankruptcy because of accrued liabilities stemming from the devastating wildfires in the West the past couple of years. One of the most important questions for the advanced energy industry was whether PG&E would be allowed to renegotiate a portion of their existing $34.5 billion in renewable energy contracts to help pay down their debts. After a tumultuous few months, developers could breathe a sigh of relief after PG&E agreed in September to honor its legacy PPA contracts. Later in September, the California Public Utilities Commission (CPUC) initiated a stakeholder process to review PG&E’s proposed plan filed in Court for the resolution of its bankruptcy along with any corresponding settlements or new regulatory requirements proposed by the Commission. It is expected that the Commission will issue a decision on both financial (e.g. ratemaking, ratepayer contribution) and non-financial issues (e.g. governance structure, alignment with the state’s climate and energy objectives, community, and workforce issues) by June 2020, although there is still some uncertainty, as the estimation of wildfire claims is not complete. 

Outside of the bankruptcy process, the wildfires also kick-started wide-ranging investigations into wildfire prevention and cost recovery plans. Just before the California Legislature adjourned for Summer Recess in July, Gov. Gavin Newsom signed a historic wildfire fund package seeking to balance the welfare of wildfire victims, investor-owned utilities (starting with PG&E), and utility employees with a commitment to uphold California’s advanced energy leadership. (For more details see here.)

The Governor’s wildfire safety and accountability package came in the form of Assembly Bill 1054, joined by companion bills (and re-purposed Budget bills) AB 110 and AB 111. The legislation created a Wildfire Fund to give utilities access to capital to facilitate payment of wildfire-related liabilities. In October, the CPUC issued a final decision approving the imposition of a non-bypassable charge on ratepayers to pay into the California Wildfire Fund, and finding that the charge is in the public interest. Also in June, the Commission adopted a set of criteria and a methodology for conducting a financial “stress test” for future wildfire cost recovery. The methodology is intended to inform determinations of the maximum amount an electric corporation can pay without affecting their ability to raise money in capital markets, which could ultimately harm ratepayers or affect their ability to provide safe and adequate service.

In May, the Commission approved a Phase I Decision that adopted communication and notification guidelines for a Public Safety Power Shut-off Program (PSPS) that allow electric utilities to de-energize power lines in case of dangerous conditions. The goal of the program is to prevent energized power lines, especially in dry and windy conditions, from potentially sparking new wildfires. However, in October PG&E faced significant backlash for a series of PSPS events that ended up leaving over 2 million customers in the dark for up to a week. In October, CPUC President Marybel Batjer sent a letter to PG&E and held an emergency meeting to hear from PG&E executives on the PSPS program. Following up on this sequence of events, the CPUC issued a press release (see here) in late October that laid out immediate steps to improve the response to future events. As one of those immediate next steps, in November the Commission opened a new investigation to examine the recent PSPS events and ensure utilities are held accountable for their actions. 

As renewable energy has become more competitive on price (see trend #2) and more corporations have set sustainability targets, large customers are increasingly looking for ways not only to power their operations with 100 percent renewable energy, but also to reduce their price volatility and reduce their energy costs. For this, they are looking to enter into long-term contracts either through their utility or with independent power producers. To give these customers the renewable energy they want, utilities in vertically integrated markets are developing new direct access programs and renewable energy tariffs.

At the start of the year, the Arizona Corporation Commission opened a docket to gather information and address possible modifications to Arizona's retail electric competition rules. The Commission is currently soliciting feedback on a series of proposals and questions with no concrete actions taken yet. 

In March, the California Public Utilities Commission opened a rulemaking to implement SB 237, reopening the state’s direct access (DA) program to additional customers. The DA program, which has been limited to about 11% of peak load since 2010, allows retail nonresidential customers to purchase electricity service directly from competitive providers. In June, the Commission issued a Phase 1 order to expand the DA cap by 4 TWh, or an additional 2% to 3% of peak load, allocated proportionally to the investor-owned utilities' service territories. Phase 2, which is expected to formally begin before the end of the year, will be focused on the second requirement of SB 237, issuing recommendations to the legislature on a full expansion of the DA cap to nonresidential customers by June 1, 2020.

In March, Florida Power & Light (FP&L) proposed a solar subscription program called SolarTogether. The program would give customers of all rate classes the option to subscribe to blocks of solar capacity (with no long-term commitment) from dedicated 74.5 MW solar power plants. FPL stated it has already pre-registered 200 customers, totaling 1,000 MW, for the program, mostly from commercial and industrial customers. In May, Dominion Energy in Virginia filed an application for a 100% renewable energy tariff that would allow customers with under 5 MW of peak demand to receive 100% of their energy and capacity from a portfolio of renewable resources owned or procured by Dominion for a premium over standard service. In August, the Minnesota Public Utilities Commission approved Xcel Energy’s application to expand its Renewable*Connect Pilot Program (a renewable energy tariff aimed at businesses that want access to renewable energy) into a full-fledged program. Xcel stated that the pilot sold out in one year and there are more than 400 customers on a waiting list. Also in October, Consumers Energy Company in Michigan proposed revisions to their existing voluntary green pricing programs. 

Community choice aggregation (CCA) or municipal aggregation, although not new, has also risen in popularity the past couple of years, driven in large part by communities wishing to take control over how their energy is generated. The concept of CCA is fairly simple. CCAs are classified as governmental entities, most often formed by cities and/or counties, that procure power on behalf of their residents. While the CCA provides power for residents, the designated utility still continues to provide transmission and distribution service in the area. 

In California, CPUC staff has estimated that by 2025 over 85% of California’s IOU retail load could be served by Community Choice Aggregators and other DA providers (up from about 20% today). On the opposite coast, New York recently refined its framework to make it easier to form CCAs, which has led to several municipalities filing implementation plans. In January, the Massachusetts Department of Public Utilities opened an investigation into improving the retail electric competitive supply market in Massachusetts, including increasing customer awareness of the competitive market and the value it can provide. In June, the DPU established two working groups which, among other things, will focus on improvements to the Energy Switch website, including but not limited to the display of municipal aggregation products. This is a timely investigation, as in June, the City of Boston petitioned the DPU to approve a community choice aggregation plan to procure power on behalf of its residents; that petition is still pending.

Non-wires alternatives (NWAs) are increasingly looked at as viable options in several key states. In a business-as-usual scenario, if a utility has an infrastructure need — usually the result of new load growth or the deterioration of an existing asset — it will choose to invest in new poles-and-wires solutions. For example, a utility will replace a transformer, upgrade the feeder or build a new substation. The utility would then earn a profit on the newly invested capital. An NWA (e.g., targeted energy efficiency and demand response programs or energy storage) may meet this need at a lower cost. But if the NWA is classified as an operating expenditure, it will not present an earning opportunity for the utility. Many states are starting to recognize this disincentive and are exploring potential solutions. Perhaps the most well-known example is Con Edison’s Brooklyn-Queens Demand Management Program.

At the start of the year, based on the Smart Grid Policy Act of 2010 and following a multiyear stakeholder process, the Maine Public Utilities Commission designated Central Maine Power and Emera Maine as non-transmission alternatives (NTAs) coordinators, in order to develop cost-effective substitutes for traditional transmission projects in the Pine Tree State. As a result, in June the utilities filed a report with recommendations (and a supplemental report in October) for a rate incentive that would eliminate the existing bias in favor of transmission and distribution investments over NTAs. Specifically, they recommended a revenue-decoupling mechanism, a ratemaking approach to treat NTA investments in a similar manner to T&D investments, and an approval process for NTA proposals.

California has been deep in its distribution investment deferral framework (DIDF) process — an annual process (first implemented in 2018) to identify, review, and select opportunities for third-party owned DERs to defer or avoid traditional capital investments. In May, the Commission issued a ruling that modified the DIDF process, most notably increasing the data requirements for utilities to include in their grid needs assessment and distribution deferral opportunity report and requiring a detailed narrative to accompany submissions. Following the utilities filling these reports in August, the companies are scheduled to launch solicitations for selected DER projects by the end of the year. (See here for a retrospective on how the process has unfolded over the past couple of years.)

In addition to the actions mentioned above, a few other states have continued their existing investigations into NWAs in 2019, including Hawaii, Michigan, Missouri, and Minnesota.

Keep up to date on all regulatory action with AEE's PowerSuite. Click below to start a free trial: