By info@greentechmedia.com
You probably don’t remember this, but 15 years ago people still debated whether the growth of distributed energy would fundamentally transform the U.S. electricity system.
Sure, there were a million operating solar projects. Google had purchased a smart home thermostat supplier for $3.2 billion. And Elon Musk had grand visions of turning his electric vehicle company into the world’s largest stationary battery provider and distributed solar company. But most Americans had no idea that the grid’s makeover had begun and would soon upend a century-old industry.
Why not? Because 15 years ago the major players in the electricity industry — utilities, distributed energy providers, regulators and policymakers alike — had not yet firmed their own approaches to the growing wave of distributed energy. And as a result, multiple potential futures lay ahead.
Version one: Aimless transformation
It started with solar power. Solar technology had been around since the 1950s, but a combination of rapid cost declines, stable federal incentives and new financing models led to an installation boom beginning in 2010. By the end of 2015, the U.S. was home to over 25 gigawatts of solar power generating capacity, which had just surpassed 1 percent of all electricity generation in the U.S. Given state and federal incentives, solar was already cheaper than residential retail electricity in 20 states, and new utility-scale solar cost less than $0.05 per kilowatt-hour, making the technology competitive with traditional resources. Already, solar made up a significant share of all new generating capacity in the U.S.
And costs continued to fall, trending toward $1.00 per watt for a fully loaded utility-scale system by 2020.
Utilities developed a complex relationship with solar. On one hand, some utilities were happy to own and operate solar projects, having received the right to monetize the federal tax credit themselves in 2008. Others signed power purchase agreements for the output from solar projects, increasingly doing so beyond state-level mandates. But on the other hand, many utilities became embroiled in state-level disputes regarding solar compensation and net energy metering.
Underlying the turmoil was the fact that the utility business was already threatened by an aging workforce and nearly stagnant load.
Now, as 2020 approached, load defection threatened utilities from two sides. Residential customers increasingly installed their own generation (mostly solar), reducing their net power consumption by 75 percent or more. As the residential solar market grew, this had a slight impact on other customers’ bills, but a much larger one on utility earnings. Utilities in many states sought to change or eliminate net energy metering, or to increase the fixed component of customer bills. But with a few notable exceptions, the changes were incremental and insufficient to stem the flow of distributed solar growth.
In the isolated cases where changes to net metering or rates did stop solar in its tracks, the respite was brief. These changes largely took the form of wholesale export rates or new residential peak demand charges, both of which added incentives for solar customers to add battery storage and/or load control. The economics didn’t make sense initially, but by 2020 the residential solar market picked back up, this time largely incorporating energy storage and controllable loads which were optimized against customers’ hastily designed rate structures.
Meanwhile, utilities also began to contend with load defection from their largest customers. In California, large end users took advantage of direct access tariffs, allowing them to purchase power directly from a renewable energy facility instead of from their default retail provider. In Nevada, MGM casinos and Switch data centers defected entirely from NV Energy, in part because of their desire to take advantage of cheap renewable energy. Elsewhere throughout the country, large electricity consumers discovered a variety of mechanisms to procure their power directly from solar and wind facilities.
Initially, the biggest impacts were in isolated, mostly coastal states with high power prices and progressive regulators and policymakers. But as time went on, the opposing trendlines — increasing electricity prices and decreasing solar/storage costs — opened up new markets throughout the country. Utilities in states like Illinois that had previously been insulated from the impacts of load defection suddenly had to contend with the same disruption their California peers had faced years earlier, and their Hawaii counterparts before that.
This was no death spiral, but it also didn’t make for a positive outlook in the utility sector. From the utilities’ perspective, their concern for ratepayer impacts and grid reliability were going unheeded as the increasingly loud voices of solar advocates focused on utilities purely as profit-seeking monopolies.
In the early 2020s, the trend continued. The Clean Power Plan took effect early in the decade (having survived a legal challenge in its infancy), and many state implementation plans incorporated further incentives for solar. Residential customers kept installing their own generation and energy storage, more than offsetting the new load coming from increasing adoption of electric vehicles. Large customers found new ways to control their own power procurement through both on-site and off-site means. And utility earnings began to erode.
It turned out that, as utilities (and their shareholders) suffered, so did ratepayers. First, as distributed solar penetration grew, cost-shifting became a real issue. When solar represented less than 5 percent of total generation, advocates convincingly argued that it provided a net benefit to the grid, and thus to all customers. But as solar’s share hit 10 percent and then 15 percent as 2030 approached, its value to the grid decreased and rates for non-solar customers increased. Real-time and locational electricity rates might have addressed this problem by incentivizing load shifting and smart siting, but regulators were slow to adopt changes, and our rate structures are largely the same today as they were 20 years ago.
Less obvious (but just as problematic) was the gradual decline of technological innovation for the distribution grid. With utility purchasing power waning and load declining, entrepreneurs and conglomerates alike focused less attention on building solutions to optimize energy delivery and maintain reliability. So while the share of intermittent resources increased, new solutions to manage these resources never quite emerged.
That’s how we find ourselves where we are today, in 2030. We have a lot more solar, but electricity prices remain high. Distribution grid infrastructure is aging, and its technology has hardly kept up with the growth rate of these new resources. Meanwhile, climate change is a more immediate threat than ever, but we don’t have a clear vision for how to decarbonize the remainder of the electricity grid.
Version two: The balkanized grid
It started with solar power, but for a time the rooftop solar business seemed like it had been a short-lived fad. After Nevada drastically reduced the value of residential solar and applied the change retroactively to existing customers, solar companies hoped it would be an isolated case. Instead, more states followed suit. By 2020, almost half of U.S. states credited exported generation from rooftop solar at the wholesale electricity price. Fixed charges on customer bills were up, on average, 50 percent over the previous decade. And 10 states had enacted all of these changes without grandfathering in existing customers.
The residential solar market, which had been growing at a rate of over 50 percent per year from 2013-2015, started to shrink beginning in 2017. Some customers still signed up, mostly preferring to take out short-term loans to finance their rooftop systems and hoping their payback calculations would hold up. But solar companies faced a capital crunch as finance providers balked at the risk of retroactive net metering changes leading to widespread customer default. Debt service coverage ratios and yields increased, making new solar projects more expensive. Meanwhile, customer acquisition costs continued to plague residential solar providers as reports of negative value from existing customers started to reverse the diffusion effect that was prevalent in solar’s earlier days.
Where the residential solar industry installed 2.2 gigawatts in 2015, it slowed to less than 1.5 gigawatts by 2020. Although a small number of states (California and New York chief among them) remained attractive solar markets, most of the country did not.
Apart from increasing fixed charges and decreasing solar export compensation, electricity rate structures remained largely stagnant. Time-of-use rates were the exception rather than the norm and were structured based on long peak periods, rather than real- or near-real-time pricing. The incentives for load-shifting and energy storage remained limited, and those markets never quite got off the ground.
And so the U.S. distributed energy market effectively went dormant by 2020. But energy is a global market, and other countries picked up the slack. Residential solar-plus-storage became the norm in Germany, Japan and Australia. India became a major market for solar/storage combinations in the early 2020s. And remote island grids throughout the world installed microgrids, finding them both cheaper and more reliable than traditional island grid architectures. Costs for all these solutions continued to decline, businesses were built, and the U.S. largely missed out.
However, the underlying customer demand for smarter, cheaper, cleaner energy that had fueled the first wave of residential solar in the U.S. never disappeared. Distributed energy came roaring back to life in the mid-2020s — this time in the form of true grid defection. Three factors contributed to this sudden trend. First, declining global distributed energy resource (DER) technology costs, coupled with continually rising retail electricity rates, meant the economics of cord-cutting looked increasingly attractive for both individual consumers and small groups. Second, the changes enacted at the end of the previous decade — particularly rising fixed charges — increasingly rendered defection the only way to leverage the full value of on-site energy resources. Third, rather than bearing the risk of retroactive rate changes later, capital providers began to prefer to finance projects that did not rely on the underlying grid and its regulatory whims.
Grid defection ultimately came in three forms. First, individual residential customers began to defect in Hawaii, and then in other states with high electricity prices. Utilities and regulators were surprised to learn how many customers would accept slightly lower reliability in exchange for cheaper, self-controlled power. Second, local communities, neighborhoods and housing developments extended the models of community choice aggregation and local power-sharing to fully islanded microgrids. Some communities utilized blockchain technology to introduce novel methods of energy and cost sharing within a small network. Third, large consumers such as hospitals and university campuses found that, even with high reliability requirements, they could leverage their purchasing power and recent technology innovation to save money without relying on their local distribution utility.
Since 2025, the electricity industry has been in crisis. The majority of defecting customers have been in higher income brackets, while the remaining grid consumers have been left with ever-increasing electricity costs. Utilities in states with significant defection are facing real financial strain. And the uncertainty around future load patterns has led regulators to focus on extending the life of existing fossil-fuel generators rather than building new utility-scale renewables.
We reached a dubious milestone earlier this year, when the number of islanded grids in the U.S. exceeded the number of physical islands in the Philippines. How far this goes — and who gets left behind — is anyone’s guess.
Version three: Embracing the transformation
It started with solar power, which led to a series of charged regulatory confrontations from 2013-2017. But as time passed and more states confronted the need to design a regulatory structure that would last (and avoid protests), each new jurisdiction started taking lessons from its predecessors. Value drawn from elements of California’s experiments with locational ratemaking, New York’s net energy metering replacement, Texas’ incorporation of distributed energy into wholesale markets and more. It took some time, but eventually the major parties (utilities, regulators, policymakers, DER providers, and advocates) agreed on a set of principles.
They agreed that distributed energy resources should be compensated according to their value, including avoided distribution costs and societal/environmental externalities.
They recognized the need to protect the prior investments of existing customers rather than applying changes retroactively.
They agreed that the optimal long-term solution would retain both the electricity grid and the utility as central components of a distributed energy system, and that profitable utility enterprises would benefit the entire system.
They realized that rate structures would need to evolve to become more location- and time-specific in order to maximize the value (and minimize the systemic cost) of all the new resources that would soon emerge on the grid.
They expressed willingness to cross-subsidize or provide financial support where necessary to ensure equal reliability and affordability for all electricity customers.
Though these principles were crystallized through utility-of-the-future regulatory proceedings in early-adopter states, they quickly spread throughout the country as 2020 approached. Armed with these principles and newly opened regulatory dockets intended to guide the future of DERs, utilities felt emboldened to innovate.
Some utilities acted as front-end customer acquisition engines for the next wave of DERs, acting as their customers’ trusted energy advisors. Some opened marketplaces, while others partnered with Google on Project Sunroof and customer-facing services.
Other utilities incorporated DERs into their resource planning processes and began soliciting behind-the-meter resources as an alternative to capital investments in the distribution grid. In support of lower-cost DER alternatives, regulators build mechanisms for utilities to earn profit on their procured services, in addition to capital investments.
At the urging of large customers, utilities started tailoring green tariff programs and site-specific power purchase agreements for individual customers. The few customers who had defected from their utility in the early days remained the exception as utilities increasingly offered differentiated service based on their large customers’ needs.
In a few states, utilities transformed entirely into platform businesses, managing the grid’s operations while facilitating millions of transactions amongst sources of load, generation, storage and ancillary services.
Meanwhile, regulators across the country reformed electricity rate structures based on the new set of shared principles. Rates became more time-variant and location-specific, sending signals for DERs to be sited where their value is highest. Utilities were well positioned to help ratepayers navigate these more complex rates, and many utilities developed a new form of energy auditing focused around savings optimization through DER investment. Independent system operators created rules to enable DERs to participate in wholesale markets, and DER aggregation became the norm.
By the mid-2020s, nearly every major investor-owned utility had a new business architecture. Their sources of earnings diversified, which made their businesses more resilient to changes in load growth, commodity prices and technology evolution.
Today, the prototypical homeowner has some form of generation, load control and energy storage at her residence. Her personal grid infrastructure is optimized for her own savings and load based on the needs of the grid. An aggregator bids her capabilities into wholesale markets and periodically to the utility for grid services. But she doesn’t much notice any of this. She’s just happy that her electricity is efficient, intelligent, automated and cheaper than it was a decade earlier.
Shayle Kann (@shaylekann) leads GTM Research, the market analysis arm of Greentech Media.
Read more here:: Greentech Media News