In August, we published our list of the top 10 utility regulation trends of 2020, so far. With a tumultuous 2020 largely in the rearview mirror, we now look back on the 10 trends that defined the utility regulatory arena this year. It is difficult to overstate the influence COVID has had on virtually every facet of the energy sector – and utilities were no exception. Nor is it possible to ignore the impact that extreme weather events have had on utility planning and operations. On top of that, the outcome of the presidential election promises to shape the federal energy regulatory landscape for years to come. Because of – or  perhaps in spite of – these transformational shifts, advanced energy is well-positioned for continued growth in 2021.

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1. A Tale of Two FERCs

With President-elect Joe Biden and Vice President-elect Kamala Harris poised to lead the country in January, it is certain that the new administration will bring sweeping change to federal energy policy. Within the set of federal agencies seen as critical to advancing those goals, all eyes are on FERC as a crucial lever to ensure that wholesale electricity markets and the transmission grid are poised to support Biden’s promised “clean energy future.”

This heightened spotlight on FERC comes after a 2020 in which the agency made moves that both erected new barriers to the development of advanced energy resources in wholesale markets and removed others. A new FERC Chair tapped by President-elect Biden will be faced with managing the conflicting courses they present. 

FERC continued in 2020 to double down on the implementation of new wholesale market rules challenging states’ ability to implement aggressive clean energy and environmental policies. In late 2019, FERC ordered PJM Interconnection to implement the Minimum Offer Price Rule (MOPR), which places limits on capacity market participation by resources supported by state policies, such as renewables participating in Renewable Portfolio Standards, nuclear plants receiving revenues from Zero Emission Credit programs, and even demand response and energy efficiency resources participating in retail demand-side management programs. The MOPR sets a price floor on these advanced energy resources that artificially raises their bids in the capacity market, making it more difficult for these resources to compete in wholesale capacity markets. FERC did approve provisions of PJM’s compliance plan that could mitigate some of the MOPR’s anticipated negative effects, without eliminating them entirely, but it also rejected requests to reconsider a similar policy it imposed in 2018 in ISO New England, and even expanded application of it in the New York ISO. As a result, some PJM states with strong clean energy  commitments, including Illinois, Maryland, New Jersey, and Virginia, are considering whether to leave the PJM capacity market. The PJM MOPR is being challenged in court, and  President-elect Biden will likely appoint a new FERC Chair opposed to the MOPR policy, but that Chair may not have enough votes to reverse the policy.

On the other hand, 2020 also saw FERC take a landmark step to remove barriers to distributed energy resources in wholesale markets. First, in July, the U.S. Court of Appeals for the D.C. Circuit delivered an important victory for FERC by affirming its landmark Order No. 841, which required wholesale market operators to open their markets to participation by energy storage resources. Certain states and utilities sought review of FERC’s determination in Order No. 841 that energy storage resources located on the distribution grid or behind the meter must be able to participate in wholesale markets without interference. The court upheld this aspect of FERC’s order, finding that its focus on ensuring that these storage resources can compete in wholesale markets fits squarely within the agency’s jurisdiction and does not intrude on the jurisdiction of the states.

Following the court ruling affirming Order No. 841, FERC ordered wholesale market operators to open their markets to distributed energy resources (DERs) in Order No. 2222. This long-awaited order builds off Order No. 841 by requiring that DERs have the ability to aggregate and participate on a level playing field in wholesale markets – effectively opening the door for new revenue streams for DER owners, new business models for DER aggregators, and new flexibility for the grid. However, the impact of the order will largely depend on how regional transmission operators (RTOs) implement it. With proposed implementation plans due to FERC in July 2021, advanced energy companies are gearing up to actively participate in the stakeholder processes where these decisions are made, working with trade groups like AEE and others. 

2. Regulators Rush to Contain the Fallout from COVID-19

 COVID-19 has fundamentally altered the outlook for many economic sectors in 2020 and beyond. Energy is no different: over 13,000 dockets mention the coronavirus, underscoring the myriad ways the pandemic has touched all aspects of utilities’ core business. Here are four ways that the pandemic has transformed utility regulation this year.

First, whether they liked it or not, public utilities commissions (PUCs) were thrust further into the digital age. Virtually all aspects of regular Commission business moved online with varying degrees of success. States like Kentucky, Mississippi, Ohio, Pennsylvania, and Texas, paved the way for the e-filing of Commission documents. Countless workshops, hearings, and technical conferences were all held via videoconference. The National Association of Regulatory Utility Commissioners even developed a guide for PUCs on how to run effective virtual meetings.

Second, many PUCs have responded to the economic impact of COVID-19 by putting disconnection moratoria into effect – putting utility customers on more stable footing as they navigate the financial challenges of the pandemic. However, by the fall, state policy toward such moratoria began to diverge. Currently, 26 states have allowed disconnections to resume and another 15 have voluntary moratoria in place that utilities may choose to adopt. Only 10 states have active disconnection restrictions in place.  Some states also used moratoria dockets to home in on COVID-19’s direct impact on customers and utilities. The Public Service Commission of Wisconsin required its regulated utilities to track and report a wealth of customer information during the pandemic, including arrears statistics, utilities’ plans to communicate collections information to customers, and the financial impact on utilities from arrears. In May, the Massachusetts Department of Public Utilities established a Customer Assistance and Ratemaking Working Group to develop appropriate policies that would support customers during the pandemic. Similar dockets are active in Maryland, Michigan, Connecticut, Texas, and Arizona.

Finally, some states have opened dockets to consider the bigger picture and develop strategies to drive economic recovery after the pandemic subsides. The New York Public Service Commission used an existing docket to contemplate the effect of COVID-19 on the New York’s electric vehicle programs and charging infrastructure deployment to ensure that the state stays on track for meeting the goals in the landmark Climate Leadership and Community Protection Act (CLCPA). These programs have also bolstered New York’s status as a leader in clean energy jobs. In Hawaii, the PUC considered how clean energy projects like the Community-Based Renewable Energy Program could meaningfully contribute to the state’s pandemic recovery. 

3. PUC Elections Favor Incumbents

In most states, Commissioners are appointed by Governors. However, in 10 states – Alabama, Arizona, Georgia, Oklahoma, Louisiana, Mississippi, Montana, New Mexico, North Dakota, and South Dakota – commissioners are elected by voters at either the state or district level. Nine states (all but Mississippi) held public elections for PUC commissioners this past November, with every incumbent that ran for reelection reclaiming their seat.  Only in instances where commissioners were termed out or declined to run for reelection did Commissions see a shakeup. In Arizona, newcomers Anna Tovar (D) and Jim O’Connor (R) picked up two open seats. 

Also as a result of the election, the number of publicly elected commissions will drop from 10 to nine as New Mexico voters approved Constitutional Amendment 1. Passing with over 55% of the vote, the amendment transforms the New Mexico Public Regulation Commission (PRC) from an elected body to an appointed one and reduces the number of Commissioners from five to three. Commissioners will be appointed by the Governor, with candidates nominated by a bipartisan nomination committee and then confirmed by the New Mexico Senate. 

4. More States Reach for 100% Clean Energy

From coast to coast, momentum behind 100% clean and renewable energy targets has continued to grow. Now, 18 states, Puerto Rico, and the District of Columbia have established 100% clean or renewable energy targets.

The latest state to do is Arizona, with an announcement to adopt a 100% clean energy goal by 2050. Receiving a 4-1 vote at the Arizona Corporation Commission (ACC) in November, the rules formally direct the state’s investor-owned utilities to retire fossil generation by mid-century while also establishing targets for energy storage deployment. The decision will be released for public comment with a final ACC vote in early 2021. Despite some commissioner turnover at the ACC due to the November election, it seems likely that the 100% clean energy rules will be approved.

Nevada voters also reaffirmed that state’s commitment to renewables this November by comfortably approving Question 6, a constitutional amendment that directs utilities in the state to source at least 50% of their electricity from renewable generation by 2030. Nevadans already voted on this same question in 2018, but as a constitutional amendment, voters needed to approve the initiative twice. In addition, the state legislature passed an identical standard into law in their 2019 legislative session, but with approval of Question 6 the 2030 RPS requirement cannot be easily repealed by a future legislature. 

Virginia became the first state in the Southeast to join the 100% clean energy club by passing the Virginia Clean Economy Act (VCEA) in March, which puts the Commonwealth on a path to 100% carbon-free electric power by 2045. The Act also significantly boosts Virginia’s energy efficiency and energy storage targets, which will support a cost-effective transition to the state’s 100% clean energy future. The State Corporation Commission has already opened a docket to iron out regulations and targets pursuant to VCEA’s energy storage provisions.

Beyond state authorities, at least 17 utilities have pledged to transition to 100% clean or renewable energy. This geographically diverse portfolio of companies also includes major players like Xcel Energy, Arizona Public Service, and Duke Energy.  

5. Transportation Electrification Charges Ahead

Momentum on transportation electrification grew throughout the year in spite of COVID-19. Well over $1 billion in new utility transportation electrification programs were approved, positioning electric vehicles (EVs) for continued growth in a post-pandemic economy. California, the country’s undisputed EV leader, continued to push the industry forward with Governor Newsom’s September Executive Order N-79-20. Developed amid a harrowing fire season, the EO establishes nation-leading goals to achieve 100% zero-emission light-duty vehicle sales by 2035 and a full transition of the state’s medium- and heavy-duty vehicle fleet to zero-emission by 2045 wherever feasible – building on the landmark Advanced Clean Truck rule approved by the California Air Resources Board in June. The EO also encourages the California PUC and its sister agencies to make further progress to hit these ambitious targets.

To that end, the California PUC approved the largest individual utility EV program to date in the form of Southern California Edison’s Charge Ready 2 program. Approved in August, the $436 million effort will support the deployment of approximately 40,000 charging stations – filling in gaps at workplaces, apartment complexes, and other key locations while providing education and outreach opportunities for customers. The approval was delivered as the Commission continues to work toward a comprehensive Transportation Electrification Framework (TEF) to guide future utility EV investments in a manner that supports state goals. A draft TEF was released in February and a final version is expected to surface early next year.

New York also achieved a major milestone in a similar docket designed to determine the appropriate role for utilities in supporting the Empire State’s transportation electrification efforts. After two years of substantive feedback, the Public Service Commission released a final order in July establishing a $701 million Electric Vehicle Supply Equipment and Infrastructure Program – spread across the state’s six investor-owned utilities – to support the deployment of over 55,000 charging stations throughout New York by 2025. $200 million of those funds will be directed toward investments that directly benefit environmental justice and disadvantaged communities. It is by far the largest suite of utility EV programs approved outside of California.

Regulators in the Carolinas also made their first forays into transportation electrification. The North Carolina Utilities Commission approved a $26 million Electric Transportation Pilot for Duke Energy in November, supporting the deployment of hundreds of charging stations in key market segments. In September, the Public Service Commission of South Carolina also approved Duke Energy’s Electric Transportation Pilot, which provides residential customers with EV charger rebates, encourages beneficial EV load management, and authorizes Duke Energy to deploy up to 40 fast chargers near major travel corridors.

Many other utility EV filings are currently underway. For example, pursuant to Senate Bill 77, Xcel Energy in Colorado filed a $102 million transportation electrification plan with the Commission in May to support the state’s goal of 940,000 EVs on the road by 2030. The proposal also offers incentives for school bus electrification and fleet advisory services.

6. Regulators Grapple With Self-Scheduling of Coal Plants

Over the past few years, the practice of “self-scheduling” coal plants has come under increased scrutiny. This phenomenon refers to wholesale market rules that allow market participants to choose to operate a resource regardless of market clearing prices in states with vertically integrated utilities. Under these rules, a market participant may designate its resource as “must run” even if the market price it will receive is below its cost of operation. This practice can be useful as a reliability mechanism to ensure that there is enough generation available to meet energy needs in periods of high demand. However, in states where vertically integrated utilities are able to receive full cost-recovery through bundled retail rates and fuel cost adjustments, many utilities have taken advantage of self-scheduling rules to run their uneconomic coal units and then charge captive ratepayers for the difference between the clearing price in the energy market and the actual cost of running the plant. In this way, utility customers are subsidizing the continued operation of plants that would otherwise not run, based on their relative economics.

Self-scheduling has come to the fore in states within the Midcontinent Independent System Operator (MISO) and Southwest Power Pool (SPP). In Missouri, the Commission has ordered all utilities to provide information during fuel adjustment and cost-recovery dockets to get more transparency into utility commitment and dispatch practices. Going one step further, in Minnesota, Xcel filed a plan at the end of 2019 to limit the use of its remaining two coal plants by moving to seasonal operations instead of relying on year-round self-scheduling. In July, the Minnesota Commission gave its approval for coal plants to sit idle for six months out of the year and only be used June to August and December to February to meet seasonal demand peaks. Xcel expects to save $8.5 million to $28.5 million on fuel costs annually and $18.4 million in total operation and maintenance costs over the remaining lifespans of the plants. In addition, the utility expects to save over $27 million in capital costs at one of the coal units.

This year, Indiana was the place where self-scheduling really came into focus. In a fuel adjustment clause proceeding, the Indiana Utility Regulatory Commission decided to investigate Duke Energy Indiana’s coal plant operational practices. Research revealed that Duke has run approximately 5 GW of self-scheduled coal at a significant loss, with customers picking up the bill. Parties to the proceeding argued that the utility should not receive cost recovery when specific coal units are run at an economic loss, and that Duke should commit to running these plants only during seasons when energy costs are higher, therefore reducing burdens on utility customers. AEE’s analysis shows that rapidly transitioning to advanced energy resources and away from coal generation can provide between $105 million and $423 million in savings to Duke ratepayers by 2025. The IURC concluded its hearings in November, and parties must file their proposed orders and briefs before the holidays for final action in early 2021. 

7. PUCs Push the Envelope on Utility Business Model Innovation

Several states continue to push forward with efforts to examine how the utility business model should evolve to meet changing customer and grid needs. In particular, there are a number of ongoing proceedings on performance-based regulation (PBR), which seeks to better align utility financial incentives with desired outcomes and state policy goals. State interest in PBR is driven in part by a recognition that the prevailing cost-of-service utility business model, which has worked well for many years, needs to evolve to better reward outcomes rather than growing capital and containing expenses, and to increase compatibility with a future where customer and third-party investments in distributed energy resources (DERs) need to be better integrated for maximum benefit to the system as a whole.

In late November, the Colorado Public Utilities Commission concluded an extensive exploration of PBR with a final report to the Legislature, pursuant to SB 236. The report captures the Commission’s year-long effort to consider how PBR could be used to further align utilities’ goals with customer and broader societal goals. Ultimately, the PUC recognizes the value that PBR brings to utility regulation in Colorado and recommends that in the near-term, greater focus should be dedicated to performance incentive mechanisms that support the state’s climate goals. Utilities’ forthcoming Clean Energy Plans and Transportation Electrification Plans provide opportunities to introduce these mechanisms.

In parallel, the Public Utilities Commission of Nevada (PUCN) has spent the last year overseeing a process to develop regulations for alternative ratemaking plans pursuant to SB 300. The legislation provided the Commission with broad discretion to encourage alternative and performance-based regulation that aligns utility business models with the state’s 2050 net or near-zero emissions goal and other state public policy objectives. The PUCN anticipates introducing a straw proposal for further comment in early 2021.

Michigan has also taken some initial steps to move PBR forward in its MI Power Grid proceeding – a multi-year effort to ensure that Michigan residents and businesses realize the benefits of the state’s transition to a cleaner, more distributed grid. Upcoming working groups will cover new technologies, business models, and utility (dis)incentives. PBR is also expected to be addressed in distribution system plans that will be filed in 2021.

8. Distribution System Planning Gets a Hard Look

Distribution System Planning (DSP) continued to gain momentum throughout 2020 as policymakers encouraged utilities to increase reliability and DER integration on the grid. While utility investments in their distribution system have traditionally been a black box, PUCs across the country are striving to make these planning processes more transparent, more inclusive of DER deployment, and better aligned with utility customer interests. 

 California took a step forward by introducing an innovative DER tariff proposal in its integrated distributed energy resource (IDER) docket in October. Building off lessons learned from previous DER procurements, the tariff proposal seeks to encourage DER aggregators to pool behind-the-meter resources needed to cost-effectively avoid traditional capital investments in the distribution system. Contingent upon approval, the PUC would launch a series of pilots to procure an array of resources to meet near- and mid-term grid capacity needs.

Colorado also concluded an extensive exploratory docket on distribution system planning and non-wires alternatives (NWAs), soliciting feedback and proposed rules from interested stakeholders on the shape of forthcoming utility DSP filings. After considering stakeholders’ robust feedback, the Commission issued a notice of proposed rulemaking in early December that further defined utilities’ DSP obligations. Ultimately, the PUC will require that a DSP filing provide a thorough overview of a utility’s investments in the distribution system to ensure that they cost-effectively support grid reliability and resilience, support the deployment of diverse energy resources including DERs, and encourage the utilization of NWAs that reduce the need for traditional distribution system investments. 

And as noted above, Michigan has commenced its second round of distribution system planning, with utilities required to file their plans in 2021. Originally a stand-alone proceeding, Michigan’s distribution system planning has been folded into the broader MI Power Grid effort, where the commission is also looking at how integrated resource planning, distribution system planning, and transmission planning interact.

9. Storage Prospects Continue to Glow

The decline in the costs of batteries and hydrogen production is fueling an increasing interest in storage, which may be critical for the deployment of renewable energy and distributed generation assets at greater scale. State legislatures continued to raise the bar this year, tasking regulators with the implementation of programs to procure and leverage storage in a manner that facilitates investment in non-wires alternatives, peaking capacity, and ancillary services. 

The Maryland Public Service Commission (MPSC) opened a proceeding to implement the 2019 Energy Storage Pilot Project Act. This Act required the MPSC to establish an energy storage pilot program, directed each investor-owned electric company to develop energy storage projects for commission approval. These storage projects could be deployed under four possible models: 1) utility-owned and operated, 2) utility-owned and third-party operated, 3) third-party owned and operated, and 4) virtual power plant.  In November, the MPSC approved with modification the six storage projects proposed by Baltimore Gas & Electric, Pepco, and Delmarva while rejecting or deferring several projects proposed by Potomac Edison.

In June, the Virginia State Corporation Commission opened a docket to adopt regulations to achieve the deployment of energy storage as required by the Virginia Clean Economy Act. The legislation requires the state’s two investor-owned utilities to develop or procure a collective 3,100 MW of storage capacity by 2035. The legislation also calls for competitive solicitations, behind-the-meter incentives, non-wires alternatives programs, and peak demand reduction programs. 

Building off of the state’s ambitious 3,000 MW procurement goal adopted in 2018, the New York Public Service Commission released its first annual “State of Storage” report in the spring and concluded that the state is on track to meet its 2030 targets, having procured 706 MW (or nearly a quarter of the 2030 goal) by the end of 2019. In September, the Commission aligned existing dynamic load management (DLM) program rules with the state’s energy storage goal and ordered the state’s investor-owned utilities to issue solicitations for DLM resources – including storage. The utilities’ filings were submitted in early December.

Last, the implementation of Order No. 841 at FERC and other RTO venues has highlighted the growing development of energy storage and the benefits they can provide in wholesale as well as retail markets. FERC and several regional transmission organizations have noted that hybrid resources are the “next wave of opportunity for storage” with a recent uptick in activity. In Texas, the Electric Reliability Council of Texas (ERCOT) is working to integrate hybrid resource technologies into its wholesale markets in order to make the power grid more flexible, efficient, and resilient by pairing battery storage with solar generation. 

Beyond batteries, hydrogen energy storage has increasingly been attracting the attention of regulators and utility companies as a potential pathway to decarbonization targets. Electrolysis costs are declining, which in turn is driving European companies to take the lead in blending hydrogen with natural gas for power generation or using hydrogen for seasonal storage. Hydrogen can be used to address “duck-curve” issues with large amounts of solar or wind energy on the grid. Some states, like California, are exploring setting standards for hydrogen in gas pipelines and others are exploring alternatives to gas. 

In Massachusetts,  as part of the sale of the assets of Columbia Gas, buyer Eversource agreed to conduct a business case analysis of potential decarbonization strategies in July, including the use of hydrogen. Also in Massachusetts, the Attorney General’s office in June 2020 called upon the Department of Public Utilities to proactively manage the transition away from natural gas to help achieve the state’s net-zero greenhouse gas goals in a new investigation.

10. Data Platforms Emerge

Several states are considering statewide data platforms to provide easier access to energy use data for customers and market participants. In 2019, New Hampshire’s General Court passed a bill directing the state’s Public Utilities Commission to establish a statewide “Multi-Use Energy Data Platform” to be built and administered by the state’s utilities. The repository is intended to standardize gas and electric customer usage data and provide easier access for customers and their designated third parties. Intervenors have filed testimony and the proceeding is scheduled to head to hearing or settlement in February. 

New York is also considering a statewide data platform and a revamp of its data access policies. The New York Public Service Commission initiated a proceeding on the strategic use of energy data that is considering two separate initiatives, laid out in staff whitepapers filed in May. The first whitepaper describes a Data Access Framework that is meant to consolidate policies across a number of existing programs and use cases into a single framework that takes into account the risks posed by the content of the data, the method of transmission, and the given use. The staff whitepaper also proposes a single certification process that would only need to be done once by a company and would be valid statewide at any of the state’s utilities or state energy agencies. A second whitepaper proposes the development of a state-run and administered data platform, dubbed the Integrated Energy Data Resource (IEDR). The IEDR goes further than the platform proposed in New Hampshire by consolidating both customer usage data and utility system data in a single location. The whitepaper envisions that by co-locating and standardizing so many different types of energy data in one place, new relationships in the data and insights into New York’s energy system will be made available to a range of users. 

Minnesota also clarified policy surrounding customer energy usage data (CEUD) with its November order approving the use of common Open Data Access Standards for customers of large utilities in the state. CEUD is critical for assessing the effectiveness of energy efficiency and conservation efforts, but can also reveal confidential information. In seeking to strike an appropriate balance, the Minnesota PUC plans to implement the Open Data Access Standards in stages while maintaining sufficiently aggregated levels of customer data to prevent confidentiality concerns.

Hannah Polikov, Ryan Katofsky, Danny Waggoner, Jeff Dennis, Matt Stanberry, and Sarah Steinberg contributed to this blog post. 

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