Back in December, we published a list of the top 10 public utility commission actions of 2016. With 2017 halfway elapsed, we check in on the top public utility commission (PUC) actions so far this year. Not surprisingly, the challenges PUCs are grappling with are scattered widely: sweeping changes in rate design, utility business model reforms, grid modernization investments, distribution system planning, electric vehicle charging infrastructure and rates, renewable energy tariffs, and interconnection requests, to name a few. Without further ado, here is a status check of the top 10 matters before PUCs in 2017 so far.

Note: some links in this post reference documents in AEE's software platform, PowerSuite. Click here and sign up for a free 14-day trial.

1. Foundational Investments for a Modern Grid

At its core, grid modernization is about investing in grid facing and customer capabilities that enable a two-way communication system between the end-user and the utility and that facilitate the seamless integration of distributed assets into the grid. So far in 2017, several utilities have proposed grid modernization plans while a few states have begun broader conversations to overhaul their systems.

In February, the Public Utilities Commission of Ohio (PUCO) approved AEP Ohio’s Phase 2 gridSMART project, which among other things includes the installation of almost 900,000 smart meters by 2021, a $20 million investment in volt/VAR technology, and the installation of distribution automation circuit reconfiguration. In April, the PUCO also opened an initiative called PowerForward to review potential regulatory policies and technological innovations that could modernize the grid and enhance the customer electricity experience.

In February, Vectren in Indiana filed a $500 million, seven-year grid modernization plan that includes investments in distribution automation technology, advanced metering infrastructure, and an advanced distribution management system. Also in February, Orange and Rockland Utilities in New York filed an application that included an expansion of their existing AMI roll-out to a full deployment for an additional $98 million. In May, Entergy Mississippi received approval to deploy advanced meters as well as a two-way communications network, a meter data management system (MDMS), an outage management system (OMS), and a distribution management system (DMS) for all of their residential and commercial customers. And in June, Hawaiian Electric Co. filed a revised $205 million draft grid modernization plan (they are expected to release the final plan on August 29) that includes a targeted smart meter deployment, the installation of advanced inverters to enable private rooftop solar adoption, and the expansion of their communication network to increase visibility into its distribution system.

2. Distribution System Planning in a Distributed Energy Future

Rapid improvement in advanced energy technologies and an influx of distributed energy resources (DER) have led states to reconsider how they undertake distribution-level resource planning. By expanding distribution planning to consider DER – such as solar PV, combined heat and power, demand response, energy efficiency, energy storage, fuel cells, and electric vehicles – in addition to traditional infrastructure investments, and by properly valuing DERs for both the benefits and costs they provide, the grid can become more flexible, reliable, resilient, and clean, all while saving money for customers.

New York, California, and Hawaii have been busy on this front for a couple years, but now several other states are getting into the game. In April, the Minnesota Public Utilities Commission issued a distribution system planning questionnaire in its grid modernization proceeding. The questionnaire sought input from stakeholders (AEE Institute submitted comments) to identify potential improvements in utility planning processes, especially in regard to the growth of DERs. Also in April, the Rhode Island Public Utilities Commission, Division of Public Utilities, and the Office of Energy Resources started a modernization initiative called Power Sector Transformation. AEE Institute and our state partner, the Northeast Clean Energy Council (NECEC) submitted joint comments.

In June, United Illuminating Co. (UI) and Connecticut Light and Power Co. submitted DER integration pilot plans as required by Connecticut Public Act 15-5. Their pilot plans include demonstration projects on hosting capacity analysis maps to provide customers and third parties more transparency into their distribution systems, DER and load forecasting to inform distribution system planning, and a DER portal and management system to facilitate the two-way sharing of information between customers and the utility. Also in June, DTE Electric Company filed a draft five-year distribution system maintenance and investment plan as required by the Michigan Public Service Commission (MPSC) in its most recent rate case. Keep an eye out for Consumers Energy’s draft distribution system plan, which the utility is expected to file by August 1. 

3. No Lack of Regulatory Activity in the Golden State

The California Public Utility Commission (CPUC) is laying the foundation for numerous regulatory reform initiatives (including several transportation electrification proposals, which will be discussed separately). However, a couple of actions stand above the rest.

In May, the CPUC issued a Staff Proposal to build on the existing long-term procurement planning (LTPP) process and adopt a process for integrated resource planning (IRP) as California grapples with the challenges inherent in a changing electricity system. The IRP is intended to optimize the state’s electricity suppliers’ resources and help in meeting the state’s policy goals – most notably the economy-wide greenhouse gas emissions reduction goal of 40% from 1990 levels by 2030. AEE has been involved throughout this process and has submitted initial comments and reply comments to the Commission.

The closely related Integrated Distributed Energy Resources (IDER) and Distribution Resource Plan (DRP) proceedings have been in a working group phase during the first half of 2017. The Distribution Planning Advisory Group (DPAG) (a spin-off from the IDER proceeding) has been meeting to work on a program to test Commissioner Florio’s regulatory incentive proposal and value DERs. The locational net benefits analysis (LNBA) and the integration capacity analysis (ICA) working groups (spin-offs from the DRP proceeding) submitted reports in March on improvements to the methodologies for DRP demonstration projects, near term improvements to the LNBA and ICA methodologies, and topics that should be considered for longer term refinement. Also in May, Commission Staff released a Grid Modernization White Paper, as part of the DRP proceeding, to evaluate investments to support DERs. And in June, Commission Staff issued a proposal on a distribution investment deferral framework to establish a process to identify, review, and select opportunities for third-party owned DERs to defer traditional poles and wires investments. 

4. New York: Valuing DER and Implementing Distribution System Planning

New York has continued to make waves with its “Reforming the Energy Vision” proceeding and several additional proceedings, which have spawned as a result. One of which is the Value of DER proceeding, where the Commission in March adopted an interim methodology for valuing DER. Specifically, the order maintains net metering for existing solar customers until January 1, 2020, and then slowly reduces the compensation for new solar users from the retail rate toward a "Value Stack" methodology that is based on the utility's avoided costs and other DER values (including wholesale, distribution, and environmental benefits).

The New York Public Service Commission (PSC) has also been busy refining the utilities’ distributed system implementation plans (DSIPs), which were required by the REV Track Two order in May 2016. Initial utility-specific plans were filed last summer (ConEdison, Central Hudson, National Grid, Orange and Rockland, and New York State Electric and Gas and Rochester Gas and Electric), with the utilities jointly filing a supplemental DSIP in the fall and a joint filing and supplemental filing on identifying and sourcing non-wires alternative (NWA) projects this past March and May, respectively. The DSIPs are one of the most important components of the REV process, as they could ultimately transform how utilities plan. Specifically, DSIPs are intended to outline how utilities’ plan to modernize their distribution grids and integrate a higher penetration of DERs, both of which will facilitate increased participation by third parties in a distributed marketplace.

And in March, the PSC, in concert with the New York State Energy Research and Development Authority (NYSERDA), filed a final Phase 1 Implementation Plan for Gov. Cuomo’s Clean Energy Standard (CES) mandate of 50% renewable energy by 2030. 

5. Addressing Shortcomings in the Cost-of-Service Regulatory Model

The traditional cost of service regulatory model worked well over the past century because it incentivized utilities to build out our electric infrastructure, while increasing sales allowed these costs to be spread out over an increasing customer base. However, new trends are threatening to undermine the existing model and have led policymakers and other stakeholders to explore redefining how utilities can make a profit.

In March, the New Mexico Public Regulation Commission initiated an investigation into its ratemaking policies, considering possible positive and negative financial incentives and re-examining how regulated assets should be defined and their costs recovered. In March, the Pennsylvania Public Utilities Commission pushed forward in its alternative ratemaking investigation, asking for feedback on experiences with different methodologies, including performance-based regulation (AEE Institute filed comments here). And in June, the Vermont Public Utility Commision opened an investigation to review emerging trends in the utility sector and examine if changes should be made in how utilities are regulated.

Over the past year, the New Hampshire Public Utilities Commission has been investigating utility cost recovery and financial incentives. In March, a working group submitted its final report to the Commission, recommending, among other things, the implementation of performance-based regulation. In May, as part of Rhode Island’s Power Sector Transformation, Rhode Island regulators held a workshop and issued a request for stakeholder comment on utility business model reforms and how financial incentives can shape policy outcomes (AEE Institute and NECEC submitted joint comments). And in May, the Michigan Public Service Commission (MPSC) initiated a proceeding to evaluate potential changes to cost recovery for utility demand response (DR) programs. Specifically, the MPSC is developing a framework for the evaluation and cost recovery of DR investments including potentially giving utilities an opportunity to earn a return on DR investments. In addition, the MPSC held a kickoff meeting on July 24 to begin a broader PBR study, with a Commission report due to the legislature in April 2018. 

6. Fixed Charges, Demand Charges, and Time Varying Rates

Rate design has continued to be a hot button issue in 2017, as utilities look for new ways to recover their costs in a changing energy landscape of low load growth and more DER. As a result, PUCs have been looking for rate designs that fairly value DER, allow utilities a reasonable opportunity to collect their costs, equitably allocate costs across and within customer classes, and send price signals to customers that align with public policy goals. Some of the designs that have been adopted have served some of those purposes more than others.   

In May, the California Public Utilities Commission issued a proposed decision adopting San Diego Gas & Electric’s new residential TOU rate designs with a later-in-the-day on-peak period (3 pm to 9 pm) and a spring super off-peak period (10 am to 2 pm on weekdays in March and April). In February, the Arizona Corporation Commission approved a 30% increase in Tucson Electric Power’s (TEP’s) residential fixed charge. However, TEP also received approval for a more sophisticated TOU rate design with a plan to make the rates default for new customers starting in 2018. TEP’s TOU rate plan is just one example of the broader move toward rates that better align with the costs of operating the grid.

Unfortunately, the fixed-charge trend still persists – albeit at a less frequent pace. Higher fixed charges secure utility revenues but fail to accomplish the other goals listed above, and proposals have largely been denied or significantly reduced. In March, Oklahoma Gas and Electric was denied its bid to double the residential fixed charge and add a demand charge for mass-market customers. Also in March, Duke Energy Ohio proposed a transition to a straight-fixed variable rate (a structure founded on the principle that fixed costs are recovered through the fixed charge and only variable costs are recovered through variable charges) for residential customers, which would increase the residential fixed charge from $6 to $22.77 per month and increase the low-income fixed charge from $2 to 18.77 per month. And in June, Duke Energy Progress in North Carolina proposed a 75% increase in the residential fixed charge in its new rate case.

Utilities have also been actively considering new rate designs exclusively for distributed generation (DG) customers – a contentious issue for many in the industry. DG advocates have countered that these new rate designs, especially demand charges, have been proposed without demonstrating a cost shift and would undercut DG’s value proposition and hinder adoption. In January, Eversource Energy in Massachusetts proposed a new optional time-of-use (TOU) rate for small general service customers, and a new three-part rate (with a fixed charge, a variable charge, and a non-coincident demand charge based on the minimum system cost of service) for new distributed generation customers, which it called a monthly minimum reliability contribution charge (MMRC). In February, El Paso Electric in Texas asked for a separate rate class for residential DG customers with a three-part rate design and a TOU rate and an optional three-part rate design for residential customers. And in March, Oncor Electric Delivery Company in Texas proposed a minimum bill (based on the customer’s non-coincident peak demand) for the delivery component of a DER customer’s bill.

7. Changes in Retail Net Energy Metering

Whereas increases in the fixed charge or demand charge component of a bill lowers the level of DER compensation under net energy metering indirectly, pressure is increasing in some states to consider changes in net metering itself.

In January, the Maine Public Utilities Commission approved revisions to its NEM rules, grandfathering existing customers under current rates for 15 years and establishing a 10-year transition period, with new DG customers in each subsequent year compensated slightly less than those who signed up the year before. This transitional approach is intended to maintain the same payback period for rooftop solar customers by slowly reducing the incentive level as the cost of rooftop solar declines.

In March, Arizona Public Service filed a settlement agreement that follows the same general principle, grandfathering existing NEM customers for 20 years and establishing a transitional step-down rate for new customers. In May, Indiana passed a bill reducing its NEM rate for new customers over the next five years until it is close to the utility avoided cost rate. And in June, Nevada passed a net metering bill that immediately restored net metering, albeit at a slightly lower rate (and with  compensation declining, ultimately to 75% of retail, as adoption increases), to finally put to rest a contentious debate that raged throughout 2016.

In March, Arkansas adopted changes to its net metering rules, adding a 25 kW cap for residential customers and a 300 kW cap for non-residential customers, with longer term changes to net metering still to come. In June, the New Hampshire Public Utilities Commission lifted its 100 MW NEM cap, grandfathered existing customers through 2040, and reduced the NEM credit for new customers to full retail energy and transmission rates but just 25% of the distribution rate. Finally, in April, the Connecticut Public Utilities Regulatory Authority suspended its open docket on broader rate design reforms until the completion of a new docket to value the costs and benefits of DERs and evaluate the potential for new rate methodologies for DG customers.

8. Electric Vehicle Charging Infrastructure and Rates

The rise in electric vehicle (EV) adoption, spurred by falling EV prices, more extended-range EV options, and the expansion of public EV charging stations, has led many states to look at TOU EV rates that more closely align with the costs of operating the grid and determine whether regulated utility companies should be allowed to own and operate EV charging stations in competitive markets.

In January, San Diego Gas & Electric (SDG&E), Pacific Gas & Electric (PG&E), and Southern California Edison (SCE) filed transportation electrification proposals with the California Public Utilities Commission. SDG&E filed a $244 million proposal, which includes $18 million for six priority review pilots on charging infrastructure and EV education and incentives (with a decision expected in October) and $225 million for 90,000 residential charging stations (with a decision expected in April 2018). PG&E filed a $253 million proposal, which includes $20 million for five priority review pilots and $233 million for two five-year charging station buildouts. SCE filed a $573 million proposal, which includes $19 million for six priority review pilots and $553 million for a medium and heavy-duty charging infrastructure program.

In May, Chairman Gladys Brown of the Pennsylvania Public Utilities Commission filed a motion initiating an investigation to review the statewide rules around third-party electric vehicle (EV) charging stations and utility tariffs for third-party EV charging stations. Ameren continued a back and forth with the Missouri Public Service Commission about installing six EV charging stations that started in August 2016. After initially being rejected in October, with the commission citing a discriminatory charging rate, Ameren filed a revised tariff, which was again rejected in April. This time the Commission justified its decision by saying that the Commission does not have jurisdiction to regulate utility-owned EV charging stations. However, Ameren did not give up without a fight, and in May the utility filed for a rehearing. But in June they were once again denied, putting the issue to rest.

Several other utilities have also proposed pilots. In April, Potomac Electric Power Co. (Pepco) in the District of Columbia proposed a $1.6 million EV pilot program through 2019 to test incentives and evaluate and obtain information on potential EV impacts on the distribution system. In April, Gulf Power Company in Florida received approval in its recent rate case for a revenue-neutral EV pilot program. And in June, the Utah Public Service Commission authorized an EV incentive and TOU pilot program for Rocky Mountain Power.

9. Renewable Energy Tariffs

As renewable energy has become more competitive on price and corporations have increasingly set sustainability targets, more companies are looking for 100% percent renewable energy offerings. To give these corporate customers the renewable energy they want, utilities in vertically integrated markets are turning to renewable energy tariffs.

In February, the Minnesota Public Utilities Commission approved two pilot programs – Renewable*Connect and Renewable*Connect Government – proposed by Xcel Energy. Renewable*Connect is a 75 MW program open to all customers, but aimed at large businesses that want access to renewable energy (and the associated renewable energy credits). The Renewable*Connect Government pilot, on the other hand, will power the State Capitol Building, Senate Building, and State Office Building with an additional 3.3 MW of renewable energy.

In May, Dominion in Virginia filed an application for six voluntary renewable energy tariffs, collectively called Schedule Continuous Renewable Generation (CRG). While offering greater access to renewable energy, the Dominion proposal would have significant ramifications for renewable energy developers. Virginia law allows customers to obtain renewable energy from non-utility companies if the incumbent utility does not offer a 100% renewables option – a right recently affirmed in a State Corporation Commission decision involving Direct Energy. But if the Dominion proposal is approved, its 100% offering would give Dominion the exclusive right to sell renewable energy in its service territory, and competitive suppliers would be boxed out of the market.

Also in May, Consumers Energy Company in Michigan filed an application for a three-year, voluntary large-customer renewable energy pilot program. The program includes two options to allow the customer more flexibility, a subscription-based program, which allows multiple customers to get part of the output of renewable energy facilities, and a “sleeved” power purchase agreement program, under which large purchasers contract for power from a specific facility through the utility.

10. Qualifying Facilities Under PURPA

Though decades old, the Public Utility Regulatory Policies Act (PURPA) of 1978 has created some new tensions. PURPA requires utilities to purchase power from qualifying facilities (QFs) – non-fossil fuel small power producers or cogeneration facilities – at predetermined rates if the QF’s costs are less than the utility's own avoided cost (the cost the utility would have incurred to supply the power itself or obtain it from another source). Now, as prices for QFs have fallen (either because of the wind and/or solar potential in certain regions, favorable incentives, or any combination of the two), certain states are facing an influx of interconnection requests. As a result, some utilities say they are getting stuck with long-term contracts from QFs that are increasing their costs and possibly reducing their reliability. Renewable energy developers and advocates counter that slashing contract terms and reducing PURPA rates would make it impossible for them to obtain financing and would deprive ratepayers the benefits of a more diverse resource portfolio. The end result has been a flurry of contested proceedings around the country.

In April, the South Carolina Public Service Commission adopted a settlement agreement in South Carolina Electric & Gas’s annual avoided costs proceeding, resulting in a 70% decrease in avoided capacity costs governing power purchases under PURPA. In May, Rocky Mountain Power in Wyoming proposed to almost cut in half the rates they pay QFs, decreasing its 20-year levelized avoided cost price from $52.15 per MWh to $31.48 per MWh. And in June,  Portland General Electric (PGE) filed a petition with the Oregon Public Utility Commission to modify its contacts with QFs. Specifically, PGE asked the Commission to lower the eligibility cap for solar QFs from 10 MW to 3 MW and to either declare a solar QF above 100 kW capacity ineligible if the owner already owns QFs for more than 10 MW of solar or lower the eligibility cap for solar QFs to 2 MW.

For a full run-down of recent state PUC PURPA petitions and investigations, see the table below:

Get your free 14-day trial of PowerSuite, AEE's one-stop-shop for all state-level legislation and regulations: