Summary of Top 10 Utility Regulation Trends of 2019

Note the original more detailed story can be found on blog.aee.net

Top 10 regulation trends of 2019:

1. 100% clean energy by…?
2. Falling cost of renewables and storage driving resource plans
3. Aligning utility performance with policy goals
4. Utilities planning for electric transportation
5. DER integration and investments in a modern grid
6. Energy efficiency, load shifting, and building decarbonization
7. Valuing DERs for their contributions to the grid
8. Wildfire prevention and protection
9. Customers making their own energy choices
10. Non-wires alternative mechanisms

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.

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.

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.

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.

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. 

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.  

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 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. 

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.

10. Non-wires alternative mechanisms

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.