Reflections on 2017: Key Trends Shaping the Power Sector


Reflection comes naturally during the holiday season. As I come to the end of my first year at RAP, I am reflecting on many interesting power sector developments from 2017. I will focus on a handful here—trends that stood out in the past year and will continue to change the electricity industry, and how it is regulated, in 2018 and beyond.

Regulatory Innovation Takes Root

In 2017, state regulators continued investigating how regulatory approaches need to evolve to accommodate changing energy markets, consumer demands, and societal goals. Notably, the approaches taken are as diverse as the states taking them. California made significant progress in its Distribution Resource Plan, and New York began implementing its Reforming the Energy Vision in rate cases.

But other states also innovated in utility incentive models and distribution system planning. Michigan, for example, is investigating performance-based regulation, with a report due to the legislature in April. Minnesota’s grid modernization proceeding began studying improvements to utility distribution system planning processes. It was a busy year in Rhode Island’s Power Sector Transformation Initiative, with the Commission largely adopting in its July order the ambitious recommendations of a collaborative stakeholder group. This was followed up in November by an interagency report examining four policy areas, including the utility business model and distribution system planning. These are just a few of the innovation efforts undertaken by states this year.

Getting the Price Right: Rate Design Continues to Evolve

Utilities and states continue to debate the most appropriate rate designs to meet future customer and utility needs. Meeting traditional policy objectives, such as revenue adequacy, fairness, and simplicity, in the face of accelerating power sector change is likewise challenging long-held views of sound rate design. Many states are asking the right questions and, crucially, avoiding major rate design pitfalls that can hinder innovation, development of distributed energy resources, and customer empowerment.

The Washington Utilities and Transportation Commission rejected a Puget Sound Energy proposal to increase the basic charge for residential customers, stating that it was “not persuaded” by Puget’s rationale for recovering transformer costs in its basic charge. Other states, such as Minnesota and Missouri, are studying time-varying energy charges to recover more shared system costs, which can meet traditional policy objectives while better aligning pricing with future system needs. This year, Maryland ordered its utilities to implement pilots that will offer time-varying supply and distribution rates, an exceptional development in a region where utilities have sought recovery of distribution system costs through high fixed charges or demand charges. California is also reviewing non-coincident peak demand charges in the commercial sector, a rate design that hinders the use of distributed energy resources. The Public Utilities Commission will be working to implement rate design changes for these customers in 2018, in an effort to correctly align rates with system costs.

Costs of Key Technologies Decline Further

The most common rejoinder to any favorable statement about renewables is that they are subsidized. Putting aside the fact that virtually all energy resources are subsidized, Michael Liebreich of Bloomberg New Energy Finance provided a convincing illustration of the rapid decline in unsubsidized renewable energy costs occurring around the world.

The table below shows what Liebreich calls “the world record prices” (i.e., the best project with the lowest risk) for solar PV and onshore wind, and how they have dropped by over half since 2015. Liebreich pointed out that prices are falling so quickly that “if you are not planning for two-cent solar, you are not on the money.”


Solar PV Onshore Wind
2015 5.8 cents/kWh 4.5 cents/kWh
2016 2.69 cents/kWh 3.0 cents/kWh
2017 1.79 cents/kWh 2.0 cents/kWh


Even with the production tax credit beginning to phase out, over the summer American Electric Power filed a $4.5 billion proposal in Oklahoma for what it calls the “Wind Catcher Energy Connection,” which the utility says can deliver energy at a levelized cost of 1.09¢/kWh (i.e., with no risk of fuel-cost escalation) over the life of the project.

The cost of battery electric storage, a key technology supporting electric vehicles (EVs), solar, and grid services, has also declined dramatically, according to Liebreich and Lazard. Liebreich estimates that EV lithium-ion batteries, whose current cost he puts at approximately $250 per kWh, will drop to about $73 by 2030. This will enable the EV sticker price to fall to the level of comparable internal combustion engine cars between 2025 and 2029. If you consider total cost of ownership, including fuel and maintenance, a favorable EV option emerges sooner. Of course, if utilities don’t manage EVs wisely—through rate design and smart charging policies—this may not be such good news. (See Beneficial Electrification, below).

Organized Markets Expand in the West

November 2017 marked the third anniversary of the Western Energy Imbalance Market (EIM), a real-time energy market that has grown steadily since its launch to include six entities covering eight states and about 38 million consumers. This year, despite lingering uncertainty about governance-related issues, additional states and utilities recognized the benefits of an organized regional market: Portland General Electric joined in 2017, and Powerex and Idaho Power plan to join in 2018. The EIM’s cumulative gross benefits are adding up—to over $250 million as of the third quarter of 2017.

Elsewhere in the West, the Mountain West Transmission Group, which includes Black Hills Energy, Colorado Springs Utilities, Tri-State, and others, proposes to join the Southwest Power Pool by late 2019. Though states continue to grapple with thorny issues around regionalization, regional markets are likely to continue growing in 2018.

Beneficial Electrification Gains Traction

Beneficial electrification (BE) is the efficient electrification of end uses that would otherwise be powered by fossil fuels to connect consumers with more affordable and reliable resources, help utilities better manage the grid, and achieve climate and other environmental goals. Over two dozen states, the District of Columbia, and other entities, such as the National Rural Electric Cooperative Association (NRECA) and National Governors Association (NGA), have recognized the innovation and potential cost savings that beneficial electrification can bring. Maryland, for example, is focused on a more “customer-centered, affordable, reliable and environmentally sustainable” power sector that can enable electrified transportation. Rhode Island is preparing to transform its power sector to accommodate beneficial electrification, including new technologies and customer-owned resources. The potential for innovation and opportunities for customer energy savings are two of the benefits that regulators are starting to recognize.

Carbon Markets and Investment Expands

In 2017, ten U.S. states—California and the nine members of the northeastern Regional Greenhouse Gas Initiative (RGGI)—revisited their carbon-market designs and further strengthened their GHG reduction goals. Two additional states, Virginia and New Jersey, also appear poised to link with RGGI. State governments were not the only ones to act. “We Are Still In,” a coalition of more than 2,500 cities, businesses, colleges and universities, and other entities, issued a declaration in June 2017 committing its members to achieving the goals of the Paris Agreement.

This is not only governmental activity, it includes investors, large and small. As one writer put it, climate activism is now coming from members of the world’s financial community, such as Norway’s $1 trillion sovereign wealth fund, the world’s largest, and they are “cashing out from the climate casino.”

Power Plant Retirements, Reliability, and Resiliency

In August, U.S. Department of Energy (DOE) staff responded to Secretary of Energy Rick Perry’s specific questions about the causes of recent power plant retirements and their implications for grid reliability by issuing a “Staff Report on Electricity Markets and Reliability.” Unfortunately, the final recommendations appended to the study were not written by Alison Silverstein, the former Texas Public Utility Commission and Federal Energy Regulatory Commission staffer tasked with writing the technical portions of the study. As she wrote in an opinion piece after the study’s release, key points on grid reliability and resilience are overlooked in its recommendations.

Silverstein noted that DOE’s staff summary got many things right, including the key finding that low natural gas costs and low electric demand growth were the principal causes of power plant retirements from 2002–2016. And she emphasized that, while wholesale markets can deliver basic grid reliability, “they must evolve to address further reliability and resilience services.”

Silverstein notes in the report that “the characteristics, metrics, benefits and compensation for essential resilience and reliability services are not yet fully understood.” The essential work needed to improve this understanding should motivate us in 2018, especially as we look back on the damage to life and property seen in 2017, and the loss of access to power experienced by millions of people across the Caribbean and southern United States after repeated tropical storms of unprecedented strength.

Looking to 2018

As we move into a new year, the pace of change in the power sector is likely to hold steady—or even increase. Entrepreneurs, utilities, regulators, and policymakers are discerning opportunities and engaging in ways that will enhance clean energy innovation and growth—with benefits for everyone.