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2025 was a year of new electric thinking. We saw many energy analysts and writers argue that there is more to the energy transition than just a shift from dirty to clean energy. It came in the form of McCormick and D’Amico’s The Electric Slide, to the IEA’s declaration of an Age of Electricity, to growing discussion of electro-industrialism, the rise of a New Joule Order, and the widespread use of the term electrostates, a term we introduced two years ago that gained broad uptake last year.

We laid out the facts in our September report, The Electrotech Revolution, which we also presented at DERVOS last fall. As we enter 2026, we compiled ten key insights from our work that we think are particularly important this year.

1. This is a technology revolution

The energy system is not just decarbonizing, it is entering a new technological age. A new generation of technologies is coming together: on the supply side technologies like solar and wind, demand technologies like EVs and heat pumps, and connection technologies like batteries, grids and software.

Each of these technologies is falling in price and rising exponentially in deployment. Individually, each is disruptive. But together, they form something more powerful. As supply finds demand and connections enable both, they reinforce each other on the way up. This is why we speak of not just a transition but a technology revolution.

This matters for 2026. Even as decarbonization slips down political agendas, the self-reinforcing nature of this technological transition does not stop. The revolution has its own momentum.

2. It brings energy abundance

Human history has seen only a handful of leaps in how much energy is at our disposal. Foragers relied on muscle and fire. Farmers unlocked the energy stored in crops and livestock, multiplying available energy by a hundred. Fossil fuels gave us another fifty-fold increase by tapping ancient sunlight buried underground.

Electrotech promises a similar leap. The sun delivers more energy to Earth every five days than all our fossil fuel reserves combined. As we move to tap into this solar resource, our energy system not only becomes more abundant, but also more immediate; moving from burning old sunshine to capturing it in real time. This is a shift from foraging fossil fuels to harvesting the sun.

As we are sure to see a year full of energy abundance debates in 2026, it is worth noting which path actually delivers on that promise.

3. It has been a long time coming

The rise of electrotech is not a recent trend. It has been coming for over a century. Electrification began in the 1880s, when electric lights and motors started replacing flame and steam. From there, electricity demand grew at 5-7% annually after 1900, as lights, industrial machinery, and household appliances spread across the developed world.

The mid-20th century brought televisions, refrigerators, and washing machines into homes. Then came the information age—semiconductors powering mainframes, then personal computers, then smartphones. The clean lab manufacturing techniques developed for chips eventually made mass production of solar panels and battery cells possible.

Now a century of evolution is turning the 2020s into a decade of revolution. This trend has been running longer than any administration or political setback. It comes with a century of momentum.

4. It inherits the momentum of the IT revolution

In many ways, electrotech is a child of the IT revolution. The precision processes that mass-produce chips and smartphones now build battery cells and solar panels. The same factories, often with the same workers trained by firms like Apple, now power electrotech’s rise. As McCormick and D’Amico argue in The Electric Slide, the tech stack underpinning electrotech is essentially the same as for digital technology. There is more in common between a laptop and a solar panel than between a solar panel and a gas power plant.

This explains why electrotech scales so fast: it inherits decades of manufacturing know-how and cost curves from IT.

It also reveals a strategic paradox visible in 2026. IT hardware and electrotech are the same industrial family. They share supply chains, manufacturing capabilities, network effects, and require the same abundant electricity. Building one without the other is incoherent. The current Trump administration push for AI datacenters and manufacturing automation while throttling EVs and solar exemplifies this disconnect. So does the EU’s embrace of electrotech even as it inhibits the AI rollout with complex regulation. Today’s new information technologies and electro technologies feed off each other. Those that starve one will weaken both.

5. The ceiling of the possible is far above our heads

We are nowhere close to the technical limits of electrotech. We already know how to run grids with 70-80% renewables at costs comparable to fossil fuels. We can electrify around three-quarters of final energy demand with technologies that exist today or are nearly commercial. Renewables and electrification could more than triple from current levels before reaching what we know is achievable.

And the ceiling keeps rising. As frontrunner regions push grids toward 90% renewables and innovators bring electrotech into aviation, shipping, and heavy industry, the technical frontier expands. By the time most catch up to today’s ceiling, the pioneers will have raised it once more.

In 2026, expect more narratives about slowing deployment in leading markets. But most of the world is still catching up. This catch-up dynamic alone sustains momentum for years to come.

6. The physics of change

Fossil systems are inherently wasteful, losing about two-thirds of their primary energy to heat and friction. Electrotech is built on efficient electricity: EV drivetrains convert around 80-90% of input into motion, while heat pumps deliver three to five times more heat than the electricity they consume. Wind and solar avoid thermal losses altogether. Physics itself tilts the system toward electrons.

This efficiency advantage extends to materials. Electrotech uses eternal sunshine and wind rather than one-time use fossil fuels; therefore it needs roughly 50 times fewer raw materials than fossil equivalents. This gap widens as innovation continues to improve efficiency and reduce material requirements. We should expect 2026 to be another year of such innovations and commercializations—sodium batteries being one example to watch this year.

7. The economics of change

Electrotech and fossil fuels follow opposite economic trajectories. As demand for electrotech rises, new, more efficient factories lower production costs through learning and economies of scale. Solar, wind, and batteries sit on learning curves with costs falling about 20% per doubling. Solar module costs have dropped 99% since 1980, wind by 80%, batteries by 99%.

Fossil fuels work differently. As demand rises, new, more expensive fields must be developed, driving prices up. After decades of these opposing trajectories, we have recently hit cost parity for key electrotech—solar, battery storage, and EVs. Today that means solar-plus-storage in India at $40/MWh and Chinese EVs below $10,000.

This matters acutely for 2026. Affordability is the dominant concern across politics and policy. Five years ago, affordability pressures would have pointed toward fossils. Today, they point toward electrotech. The crossover has happened. The cheaper path is now the electric path.

8. The geopolitics of change

Three-quarters of the world relies on fossil fuel imports. Get cut off, and your economy grinds to a halt. Countries have fought wars over energy access and structured foreign policy around securing supply.

Those risks are rising. Trade tensions are escalating. Geopolitical fractures are deepening. In this environment, every country is looking for alternatives.

At some point, they will look up. The sun delivers energy everywhere. 92% of countries have the potential to generate at least ten times their own energy demand from domestic renewables. With electrotech, every country can become energy independent.

If 2026 is indeed going to be a year of rising geopolitical tensions as many expect, we should expect countries to accelerate electrotech deployment as a strategic priority. Those that sow electrotech will reap sovereignty.

9. Electrotech is a tool for rapid development

For decades, development meant following the fossil path. Rich countries burned coal and oil to industrialize, and emerging economies assumed they would need to do the same. Electrotech allows them to skip that step entirely.

The fastest change is now happening in emerging markets. ASEAN leapfrogged the US in electrification in 2023. Solar deployment has surged across Asia, Latin America, and Africa. In many countries, solar has gone from the smallest to the largest source of new capacity in less than a decade.

The pattern makes sense. Some 80% of the world’s population lives in the sunbelt, where solar resources are abundant and cheap. For countries building energy systems from scratch or expanding rapidly, solar plus storage offers a faster, cheaper path than fossil infrastructure. Development no longer requires a fossil-first pathway. Electrotech is becoming the foundation for growth.

We should expect more emerging market leapfrogs in 2026 as well as a pullback from fossil fuels. As solar and storage costs continue to fall, emerging economies will increasingly look to exit expensive LNG contracts in favor of domestic renewables.

10. Electrification is the geopolitical differentiator today

The world is rapidly building new electricity supply. Solar and wind capacity is being deployed at record pace. But supply alone does not determine competitive advantage. Today, the differentiator is electrification; putting that new supply to work by electrifying transport, heating, and industry.

China has grasped this. It is scaling both supply and demand simultaneously: solar farms and EVs, wind turbines and industrial electrification. This approach, which we call the electrostate model, uses domestic markets to drive down electrotech costs and improve quality, then capture export markets with superior products.

The West is deploying substantial new supply. But electrification of demand has lagged. Solar and wind without EVs, heat pumps, and industrial electrification is an incomplete strategy. As we move through 2026, the question is whether Western economies will match China’s integrated approach, or continue building only half the system.

Entering the second half of the decisive decade

For the first time, humanity can harness the power of the sun directly, at scale, and in real time. After a century of evolution, electrotech is breaking through in a decade of revolution.

The 2020s are this decisive decade. This is the decade when manufacturing reaches global scale, when uptake s-curves enter their steep ascent, and when costs cross over from more expensive to cheaper than incumbents. We have just passed cost parity for solar, batteries, and EVs. From here, the economic logic only strengthens—as do the physics and geopolitics drivers of change.

Countries and companies that recognize this shift will shape the next era of global competition. Those who resist will find themselves left behind. The revolution has its own momentum. 2026 is another year deeper into it.

For more, watch the conversation from DERVOS on Energy Dominance and the Electrostate featuring Daan Walter.

Fred Stafford here. This post is an excerpt of an essay by myself and geographer Matt Huber for Damage Magazine. Rather than posing leftwing arguments in favor of “big public power” like the TVA, as we have done repeatedly — and as Matt did on DERTF episode #37 and at DERVOS — here we pose leftwing arguments in favor of the regulated public utility model in general. Yes, even when investor-owned. Avowed libertarian Pier LaFarge already delivered the same basic arguments as ours on DTF episode #48; we hope the DERTF community might appreciate our own, socialist articulation of it. 

Our case to “reclaim the utility of utilities” is practically heresy among progressives interested in decarbonization, who instead see new markets, new price signals, new energy firms, and ever-present competition as key steps on the path to clean energy growth. Those advocates see clear limitations of the utility model — sometimes for good reasons, which we cover in our historical look at the utilities’ rise and fall over the 20th century — but we see risky limitations in the competitive alternative too. We’re not alone in that concern; the new book “The Price is Wrong” by geographer Brett Christophers has been making waves everywhere from the Financial Times to Heatmap for its core critique about the lack of profitability of renewables development.

But what Christophers and so many others miss in such (correct!) analysis of renewables investment — apart from the need for bigger, more centralized clean energy infrastructure beyond renewables, like nuclear or pumped hydro storage — is that the competitive independent power producers aren’t the only way for the creative motor of profit to drive the development of critical infrastructure.

Now that the era of stagnant load growth is behind us we think it’s time to return to the growth engine of the utility model, to rebuild that lost institutional capacity that James lamented in conversation with Mark Nelson in DERTF episode #43. We'd prefer more New Deal-style public power — ideally with costs socialized by progressive taxation than by the “regressive tax” on ratepayers — but even private ownership of regulated “public utilities” would embody the institutional model we need.  

The Utility of Utilities

Climate activists are no fans of electric utilities. But the market-based alternatives that they often prefer will not deliver infrastructural change at the scale we need.

Taller than the Washington Monument, planted in ocean-floor monopile foundations weighing as much as four 747s, heaving blades the length of a football field, offshore wind turbines were meant to be the new American clean energy juggernauts.

Generating power at a larger scale and more frequently than onshore wind turbines, though still intermittently, offshore wind has been central to the decarbonization goals of President Biden and of Atlantic blue states. As of this past January, decades behind its European counterparts, the American offshore wind industry has two turbines, off two coasts, finally delivering power.

But last fall, the future of this focal point of the energy transition began tumbling into a political-economic crisis. Post-Covid supply chain bottlenecks and rising inflation led to escalating losses and plummeting share prices for German wind turbine manufacturer Siemens. Flagship offshore projects were canceled in New York, New Jersey, Massachusetts, and Connecticut. Their total power capacity amounts to about one-fifth of Biden’s goal for offshore wind supply by 2030, the delays all but guaranteeing a miss.

Each canceled project was undertaken with—and financially completely dependent upon—state-negotiated contracts in state-designed competitive auction processes to purchase “renewable” certificates from competitive developers. The power markets aren’t enough; developers of these immensely capital-intensive projects also need subsidies on top. It’s a common scenario for all renewable energy procurement, not just offshore wind, in blue states in particular.

Meanwhile, one massive 176-turbine project off the coast of Virginia is going forward without a hitch. It is owned and managed not by a competitive developer, but by the vertically integrated electric utility Dominion Energy. As a utility, they are afforded economies of scale and efficiencies in system planning. Dominion’s project is larger than the others, and while other projects are lacking in ships to install turbines (one example of the “supply chain problems” plaguing the industry), Dominion is simply building its own.

As a regulated public utility, E&E News explains, Dominion “uniquely enjoys” an investment model unavailable to those capitalists only seeking to develop wind energy alone: thanks to its regulated utility status, “its investments are paid for by electric consumers, with utility regulators approving a return on the investment as profit.” That older model lies in stark contrast to one in which increasingly bespoke markets, price signals, financial instruments, and auction processes, designed in tandem with state policies, lure capitalists without the burden of serving customers.

Newfangled markets and competition versus old-fashioned utilities. When it comes to building tomorrow’s clean energy infrastructure, it’s hard to find anyone left of center arguing in favor of the latter arrangement. That is, except for some of the labor unions representing the energy workforce.

The reality of climate change presents a need to develop clean energy. To decarbonize the whole economy, state-of-the-art modeling from Princeton suggests we’ll need to triple or quadruple electricity production by 2050. This entails not just some wind turbines here and solar panels there but a nationwide remaking of the industrial landscape. What if that older utility model offers greater potential to build the clean energy infrastructure we need?

To continue reading this essay go to Damage Magazine

The Fractal Grid: Part III

The tyranny of peak load – Data is the new copper – Telemetry hardware

As mentioned in Part II, unlocking the full value that Distributed Energy Resources (DERs) can provide to the distribution system depends on real-time awareness of infrastructure constraints. In turn, the Distribution System Operator’s (DSO) degree of visibility into these constraints and operating parameters depends on how well they can infer the state of the electrical network from available data, a technique called “state estimation”. The quality and comprehensiveness of the data generated from the system’s telemetry equipment is paramount to determining how close the DSO’s digital representation captures the physical reality of the network. 

The ultimate goal of state estimation is to establish electrical connectivity between nodes in the network. In other words, the inferred state needs to reconcile the electrical relationships between all the meter sockets, secondary wires, service transformers, primary wires, fuses, jumpers, switches, feeder breakers, substation buses, and finally, substation transformers in the distribution network, each of which has the ability to redirect or modify power flow and therefore change relationships. This level of awareness is critical for system optimization because it enables the DSO to attribute value and fair compensation to load shaping. Without knowing which feeder breaker a home is drawing power from at the moment the price signal is sent, the DSO cannot determine whether load shaping from the home’s battery would alleviate the target constraint or have unintended impacts elsewhere. Without detailed state estimation, DSOs don’t know whether DERs are doing what they are getting paid to do. 

Today, utilities have selective real time visibility into important larger junctures in the network, like substations and some medium voltage switches, but minimal real time visibility into meter data at final points of consumption and often no visibility at all into the intermediate nodes in the network, like secondary transformers and line switches. Some utilities have not even rolled out AMI across their full service territories (currently around 75% of consumers have AMI) and even fewer make real-time usage data available to customers (only 2.9% of federally-funded smart meters have this capability, according to Mission: Data).

Topological awareness – monitoring the path and status of lines – is even more desolate, as the geo-coordinates of every line and status of every switch and feeder breaker are often unrecorded or belately recorded in digital models of the network. Some electrical infrastructure generates data from Supervisory Control and Data Acquisition (SCADA) systems and can be updated remotely, but most of the essential and sometimes improvisational adjustments that linemen make to jumpers, switches, and elbows on a week-by-week basis evade the digital model, despite having severe implications for electrical topology and connectivity. These challenges grow with the complexity of the network; the percentage and quality of telemetry coverage deteriorates as the quantity of nodes, interlocking switches, and junctures increase. Some feeders even tie back to themselves. Any digital model hoping to lay the foundations for state estimation must accurately capture this complexity and quickly respond to every lineman, tree, or snowplow that advertently or inadvertently changes topology (and therefore power flow).

However, the biggest challenge could be that the hardware that has been deployed might not be capable of generating data with sufficient granularity to establish electrical connectivity between nodes. Most smart meters and SCADA systems are asynchronous, meaning they can measure volt and amp magnitudes but not the phase angles of the alternating voltage and current. Some argue that asynchronous measurements can only determine how much power is flowing through a given node, not where that electricity is coming from; therefore only synchronous measurements, which record phase angles, can enable the DSO to determine which upstream transformer a meter is electrically connected to at a given point in time.

Phasor Measurement Units (PMUs) are a telemetry technology that records voltage, current angles, and magnitudes of every present electric phase of an alternating current at a frequency measured in milliseconds. Theoretically, assuming there is a PMU at every node, electrical connectivity between nodes can be calculated by comparing their phase angles, making it possible to reliably link meters to upstream feeder breakers or transformers. Although PMUs have actually been around longer than their more prevalent counterparts, they are more expensive, and as a result only a fraction of smart meters and telemetry hardware installed by utilities have the capability to take synchronous measurements. 

Due to these data and telemetry challenges, state estimation has largely been confined to academic papers and the transmission system. On the bulk grid, every node above 230 kV is equipped with the telemetry equipment needed to produce input data for the power system optimization software used by ISOs. Although it is unclear what connectivity awareness exists below the microgrid demarcation, resiliency service providers at the consumer level always install the requisite telemetry and controls required to ensure 99.99% uptime at reasonable cost to the socially-essential hospitals and… hydroponic cannabis farms they service. Even residential products sold by companies like Span and Sense market visibility within the home as a defining feature and selling point.  

The distribution grid represents the hardest technical and collective action problem. The smaller the lines, the more likely switches are opened and closed without any digital representation and the less likely telemetry coverage is close to sufficient. As a result, distribution planning runs primarily via static reports, DER interconnection is done via manual, bespoke projects, and real time operation is highly conservative and ruled by the extremes at the upper tail of the distribution. With minimal awareness, operators responsible for reliability have to assume the worst, creating tyranny by static, maximal ratings where constraints and their corresponding price signals are updated infrequently and set almost exclusively by peak load events.

However, some startups are betting that advances in software and machine learning can help distribution system operators roll back a bit of fogginess and capture unrealized value even without PMUs at every node. 

Kevala provides data-driven distribution planning services for utilities, and in doing so, is amassing the data required to build a "1:1" map of the grid capable of running power flow analysis down to the service point level, a critical first step towards state estimation. It seems natural that automated interconnection and active network management would live within the same data ecosystem, and as outlined in “The Digital Rate Case” by Jake Jurewicz, analyzing, siting, approving, and efficiently managing DERs via one service offering is a great product experience for developers, utilities, and regulators alike.

Camus, like Kevala, is selling directly to infrastructure owners but focused on real-time management for smaller municipally-owned utilities before expanding to investor-owned behemoths. Inspired by recent advances in distributed computing, their product is focused on providing the operational visibility and decentralized control required to coordinate DERs owned by multiple independent parties. 

Both companies, as well as established players like Palantir and GoogleX, are approaching the visibility gaps from different angles and could eventually be well-positioned to approximate the state of a distribution network with enough granularity to realize the vision of a fractal distribution grid, especially with potential hardware partners like SunRun and Sunnova already planning on building community microgrids. However, state estimation will advance the frontier of awareness only to the point where the marginal cost of additional granularity exceeds the marginal value provided by intelligent DER coordination. Some see distribution-level price signals as contingent on complete deployment of PMU telemetry because without the ability to couple meters to upline feeder breakers and transformers, the DSO cannot have faith that a specific action will alleviate the targeted constraint nor could they properly compensate DERs for load shaping behavior. Regardless, the point of diminishing returns may arrive sooner than anticipated unless utilities install more telemetry hardware. Even then, the overhead required to continuously run these types of markets at the distribution level might be cost-prohibitive.

Despite the technical and economic risks, the biggest open question of all rests with institutional barriers to entry. Ultimately, we can never know if this vision will work without the buy-in from those who own, operate, and control distribution infrastructure in the US: utilities. Do they have the capability, and the motivation, to build the distribution grid we need?

The Fractal Grid: Part IV 

Institutional inertia – Units of fracturing – What to build?   

“Infrastructure, and the institutions that support them, lag behind.”  — Gretchen Bakke 

The standard decarbonization template is to electrify the energy-intensive sectors of the economy currently dependent on fossil fuels and shift electricity production to renewable resources. Electrifying heating, transportation, and industrial processes will dramatically increase demand, requiring utilities to build substantially more lines, substations, and generation capacity at the grid edge to serve new load as efficiently and resiliently as possible. Whether the current institutional environment will facilitate construction of this grid, at least to the magnitude required for the energy transition to occur, is controversial. 

Two friends walk into a bar. Tyler DERden builds dope microgrids at the grid edge and has a fairly deep interest in cryptocurrency and past energy transitions. He hates franchise rights and is a bit cynical and skeptical of those in positions of power. DERblius is a wonky (in a good way) power systems optimization modeler from MIT who has been working on capacity expansion models and considering cost allocation on decarbonized grids for a long time. She dabbles in political philosophy in her free time and generally has faith in institutions but is not naive.  

Tyler DERden: Derb! Great to see you. Did you read that essay about data and the challenges of building on distribution grids? 

DERblius: Sure did, Tyler. That fractal stuff was kind of out there but I think I got the gist of it. My first thought is that this information asymmetry on the distribution grid, or rather the lack of any trustworthy information at all, makes it hard to know whether our DER Bill of Rights is being violated. We can’t enforce rights like “reasonable interconnection times” without the requisite data. What are your reactions?

Tyler DERden: It got me heated. 

DERblius: Yeah, I saw that coming. 

Tyler DERden: To me, this series illustrates that the top-down management of the distribution grid disincentivizes the build-out of a truly distributed, two-way network and puts an arbitrary ceiling on distributed generation. We have a pure market for on-site resilience at the grid edge and imperfect but functional wholesale markets, but the monopoly for delivery, interconnection, and distribution of power is a black box whose inefficiency is now leaking out in the form of high delivery costs and painful interconnection processes. We need to find a way to put the infrastructure for power delivery in the hands of the people and the market because the current institutional environment impedes beneficial evolution. 

DERblius: I don’t think setting everyone loose tinkering with the most complicated machine in the world is a good idea. Private and decentralized development of substations and wires would be bedlam. You’re underestimating how difficult it is to link the physics of a power system to a financial market; distributing electricity is, and will remain, a natural monopoly. 

Tyler DERden: The logic of this monolithic natural monopoly is unwinding before our eyes. The reason we have such limited awareness on the distribution grid, a masochistic interconnection process, and nonexistent NWA opportunities is because utilities only care about what they can rate base, which tend to be big infrastructure projects.

DERblius: To be fair, we have seen regulators force utilities to rate base new types of infrastructure, like smart meter rollouts. 

Tyler DERden: True, but even if they can legally rate base more complex operations they are still not built to do it well. In fact, they have no financial incentive to spend intelligently at all, or record a timely, accurate inventory of the assets they own, or provide quality services and products for the litany of private companies, non-profits, and consumers that are forced by law to depend on them to get anything done.

DERblius: We can selectively introduce markets and add transparency to existing institutions by providing utilities with the hardware, telemetry, data and software tools they need to build faster and more efficiently. But I don’t think the model that has worked for a century is fundamentally broken. Even the mesh network of the future will be a natural monopoly, and therefore the assumptions underpinning key laws like franchise rights will hold true. The solution is to leverage more direct political pressure, better research, and new regulatory structures align incentives and provision services from innovators like Camus and Kevala, who are systematically breaking down every reasonable excuse a utility might have to not do something.  

Tyler DERden:  I don’t think an adoption model dependent on regulatory pressure can create the hockey-stick growth curve we need. Investor-owned utilities routinely manhandle regulators because their shareholders have a vested interest in providing them with the resources required to maintain the status quo.

DERblius: I think you’re casting a lot of good, hard working people as ill-intentioned. Plus, not all utilities are made equal. Smaller and municipally-owned co-ops and utilities like Green Mountain Power have made great progress. There is much better incentive alignment when the person running your power grid is your neighbor. 

Tyler DERden: I don’t think they’re ill-intentioned, but on a macro-level, the incentives and logic of this techno-economic system only allow marginal changes and peripheral tinkering. We need to think in orders of magnitude and big paradigm shifts, which are brought into existence via carrots, not sticks. Every exponential technological transition we’ve had in the past was stimulated by willing adoption of products and processes undeniably better than their alternatives; if we are to create a fractal grid and decarbonize fast enough to address climate change, we need to realign the institutional environment. 

DERblius: What you’re missing, and what that fractal guy didn’t dive into deep enough, is how institutions scale differently than physics, which makes it much more difficult to implement the solutions you envision on the distribution grid. 

Tyler DERden: Ah, enlighten me. 

DERblius: As mentioned in those earlier essays, we’ve seen the most change at the highest and lowest levels of the grid. On the bulk grid, we largely broke up vertically integrated utilities and introduced various types of market products to reduce costs but still have a single orchestrator that steps in unilaterally as a last resort. Change slogs through a sort of oligarchy consisting of political appointees, stakeholder advocacy groups, private lobbyists, utility commissions, etc. which requires an enormous amount of cooperation just to function, nevermind initiate change, and as evident by Winter Storm Uri, things still break.

Tyler DERden: Things will always break because they’re inherently unpredictable externalities, which is why we need resiliency at the grid edge.

DERblius: Right, and we’re starting to see people and organizations take power into their own hands by deploying DERs and microgrids to hedge that risk. These independent actors have strong motives and the means to “exit” the grid. But the intermediate section of the grid reflects the “community” level, which has limited grassroots gusto in its ability to exit, small amounts of power and money flowing through its poles and wires, and the most difficult technical challenges. This makes it the hardest collective action problem, which is why we’ve underinvested in it, and therefore requires a top-down solution. It’s a public good. 

Tyler DERden: What I’m hearing is that markets always generate data sufficient for their existence but the telemetry, hardware, and data processing investments required to safely run wholesale markets stop above the distribution sinks. We see underinvestment in the remaining delivery infrastructure precisely because we didn’t expand markets past the arbitrary threshold where monopoly delivery service begins. 

DERblius: Three points. First, the threshold isn’t arbitrary. Second, you’re conflating markets for energy and ancillary services with markets for building infrastructure. There are no markets for building infrastructure and adding transmission is arguably just as painful and opaque as adding feeders and substations.

Tyler DERden: I think that’s somewhat debatable because of market products on the transmission grid like Financial Transmission Rights (FTRs), where participants pay for the right to transmit electricity and therefore have incentives to optimize power flow. If the constraints create enough price pressure, there is a market-based mechanism to justify building a new line. 

DERblius: Perhaps. My main concern, however, is about the disparities in power, money, and value flowing through the bulk grid vs. distribution grid. Microgrids have lower coordination costs because there is one independent actor procuring resilience; bulk grids have higher coordination costs but a few independent actors with huge financial incentives and political power. The distribution grid contains many independent actors with limited interest in participation, high coordination costs, and proportionally lower value per transaction. The cost of administering a market at this level is not worth it. It’s working against one of the most powerful laws in the universe: returns to scale.

Tyler DERden: I see a few reasons why the window for decentralization and more market constructs may yet crack open. The rise of variable, zero marginal cost energy production has raised the relative importance of delivering power at the exact time and place it is needed, rather than simply generating it cheaply. This makes our outdated process for building delivery infrastructure increasingly burdensome on consumers and magnifies the importance of optimizing the flow of electricity through existing wires and building quickly. Additionally, the growing importance of resiliency at the community level and technological breakthroughs from software players like Camus and Kevala, as well as hardware players like SunRun and Sunnova, could create the political opportunity for a CCA-like movement of distribution infrastructure ownership. If technology can make mini-ISOs financially viable, I can imagine many smaller T&D and generation owners springing up yet remaining interconnected using the common standards and equipment enforced by regulators today.

DERblius: Who exactly owns the infrastructure? And who, or what, coordinates the market activity of so many houses and service providers in a neighborhood? Moving up the distribution grid from single party microgrids to community microgrids with many independent parties will have seriously high standards for transparency and fairness in an environment where stakeholders, namely, individual homes and business owners, will have minimal appetite for understanding and advocating for their own interests.

Tyler DERden:  A community fund with consumer shareholders owns the substations, poles and wires, independent actors and service providers own the generation and load flexibility assets, and the futuristic ADAS providers like Kevala or Camus compete to manage the network, market, and mini-RFPs.

DERblius: How do you ensure the entity providing the DSO service, building infrastructure, and running the market does not abuse its power? You’re proposing the same information asymmetry the utility has today with less regulatory oversight. 

Tyler DERden: Transparency will be the market standard. Communities with the most at stake, such as those threatened by wildfire shut-offs, will invest in auditing the service provider. Eventually, we might even have decentralized coordination and decentralized control so no central party would have to be trusted. 

DERblius: Sounds like crypto-babble. 

Tyler DERden: Imagine all members of the community microgrid using their computers to solve the state of their distribution network, getting rewarded for it, and having the means to validate power flow calculations and payments. You could even provide fractional ownership and governance of all the poles and wires to create added rationale for not violating constraints. Who wants to damage something you own?

DERblius: Idealistic and cool… in theory. Sounds like Bitcoin but instead of solving math riddles with no purpose you’re using that computational power for something useful. Anyways, it still sounds like an expensive and risky way to deliver a public good. Plus each community’s grid is a snowflake.

Tyler DERden: Ah, baiting me with a jab at Bitcoin’s energy consumption. Anyways, that’s why I think if this is to occur, the most likely approach is for a microgrid developer to aggressively provide off-grid services for commercial and industrial loads and co-located power production. An industrial campus with a few independent actors has a strong incentive to audit their mini-market and ensure power and resilience is traded fairly and efficiently. In this way, the microgrid operator would genuinely be acting like a utility by setting rates and owning delivery infrastructure. 

DERblius: Ah, so if they can drive down the cost of this service they could attack the distribution grid market from the outside-in, pending the regulatory revolution you anticipate. But I still don't see how that necessarily means that it has to break the utility’s natural monopoly. With better performance-based regulation, utilities would pay this company to deploy a community-level microgrid, as they would pay Kevala or Camus.

Tyler DERden: True. But I think the lack of a utility incentive to provide cost-effective community resilience breaks the natural monopoly model. 

DERblius: That's where we disagree, although I think we see different means converging to the same end.

Tyler DERden: Agreed. Now let’s finish our beers, we are going to be late for the DERTFest 2022!  

Thank you to Bryce Johanneck, Elias Hatem, Colin Bowen, Jake Jurewicz and the DERTF community admins for their valuable feedback on earlier versions of this essay series.

If you are interested in writing a Task Force Feature, reach out to us on Slack!

The Fractal Grid: Introduction

Introduction – The middle child of the value stack – Unlocking Non-Wire Alternatives

The electricity grid is experiencing a paradigm shift changing how, where, and when we produce and consume energy. The Age of the Electron Part II highlighted how Distributed Energy Resources (DERs) are playing a transformative role in this transition in the following ways: 

1. Wholesale Markets: by providing energy, capacity and/or other ancillary services to markets, whether individually or aggregated

2. Non-Wires Alternatives: by reducing our need for poles and wires or optimizing their usage by being at, or closer to, demand 

3. Resilience: by providing resilience to the end user 

All three dimensions have compelling value propositions. 

With the rise of variable electricity generation in wholesale energy markets, leveraging the bevy of flexible, digitally-native electrical devices to dynamically balance demand on the bulk grid is becoming increasingly cost effective. Integrating DERs with wholesale markets has received growing political support via orders like FERC 2222 and exhibits tangible, easy-to-understand benefits like eliminating peaker plants and supporting grid emergencies.

Additionally, provisioning on-site resilience – the ability to produce or store electricity during grid outages –  is becoming increasingly important as new technologies electrify critical services like heating, transportation, and manufacturing. Resilience also capitalizes on the emotional narrative of American Individualism as marketing campaigns for products like the new Ford F-150 tout the ability to back up homes for multiple days.

In comparison, Non-Wires Alternatives (NWA) seem to be the most inscrutable value stream located in the messy middle between bulk power systems governed by wholesale markets and consumer endpoints at the point of adoption. For a variety of reasons to be explored in this series, NWAs – which will also be referred to as “Distribution System Optimization”  – is a sort of middle child, often overlooked and neglected within the DER value stack despite its growing importance. 

It is difficult to comprehend, no less sell, the value of optimizing the management and construction of distribution infrastructure because the current institutional environment does not incentivize the telemetry deployment and data processing required to facilitate system awareness at the grid edge. Today, this difficulty manifests as rising delivery costs and interconnection bottlenecks for distributed generation; long term, it will increasingly nudge DERs towards exiting the institutional infrastructure that governs the legacy grid. As the DER market continues to scale and drive down the cost of islanding, microgrid technology may even enable communities to roll back the authority of legacy institutions by owning and managing their own distribution infrastructure, potentially breaking or amending the utility’s century-old natural monopoly on the delivery of electricity. 

The focus of this four part series is exploring how and why this transition may occur, beginning with an introduction to fractal patterns and evaluation of community-level resilience and distribution system islanding in Part I. Part II is an assessment of where distribution system optimization fits into the value stack today and how it is closely intertwined with the interconnection process. Part III discusses the dearth of data on distribution infrastructure, the technical requirements for facilitating network awareness, and the implications for DER deployment. Finally, Part IV concludes the series with a philosophical debate on whether the institutions governing the distribution grid must be replaced or simply amended in order to support the energy transition.

Thank you to Bryce Johanneck, Elias Hatem, Colin Bowen, Jake Jurewicz and the DERTF community admins for their valuable feedback on earlier versions of this essay series.   

The Fractal Grid: Part I 

Grid granularity – Self-similarity – Community microgrids 

A futuristic grid driven by DERs will require a structural shift from traditional hub-and-spoke systems to fully distributed networks. What does this mean in practice and why is network structure important for the energy transition? 

There are three basic designs of distribution systems – radial, looped, and networked – determined by topology: how the poles, wires, and substations crisscross a given service territory. These terms define a gradient describing the grid from most simplistic and least fault tolerant (radial) with many spokes protruding from few central hubs, to most complex and fault tolerant (networked) with many interlocking loops and spokes per hub distributed more evenly throughout the network. Because networked systems require building more infrastructure, they are expensive and predominantly found in population centers where the costs of added redundancy can be spread over many consumers. Cheaper radial systems cover the vast, sparsely populated areas of the country; measured in total line miles, the majority of the grid is technically not a network. 

In addition to geography, network structure also depends on scale or granularity as measured by the power flowing through wires and their proximity to the final point of consumption. As shown in the visualization above, more simplistic networks tend to emerge at lower voltages closer to where power is distributed to consumers, or in other words, at high granularity (see the little houses on the left). Networked grids with high fault tolerance tend to appear at larger scales, on the transmission systems of bulk grids where it is cost effective to ensure that entire neighborhoods, towns, or regions have multiple avenues to electricity in the event a line goes down.

“Fractal” is a useful term to describe these grid characteristics because it offers a formal way to analyze network structure at different granularities. Originally coined by Benoit Mandelbrot, fractals refer to patterns that exhibit self-similarity or recursiveness (i.e. looks roughly the same) at different scales. They are properties of many different disparate naturally-occurring phenomena, from coastlines to broccoli (notice how the structure of a tiny broccoli floret mirrors the shape of the entire stalk). Additionally, fractal systems are typically associated with resiliency due to their self-similar structure and ability to behave independently at every level of granularity.

The network structure and technologies of today’s electricity grid exhibit limited fractal-ness. Some combination of a highly networked grid with renewables, storage, and gas generators appears to be a winning formula for delivering cost-effective resilience at both the ISO and microgrid levels. But as we move up the grid from resilient systems within homes, business, and campuses to the control room of an ISO, we see a change in structure and functionality at the intermediate distribution levels; they are predominantly radial and incapable of operating independently. 

So investments in the hallmarks of structural resilience appear at the largest and smallest scales of the grid but they are not truly self-similar fractals; to be fractal, resiliency would be distributed evenly throughout all hierarchies to optimize not just for uptime on the bulk system and end nodes, but at the intermediate layers constituting the neighborhood or community level as well. Distribution networks serving these communities rarely, if ever, have the capability to island. By implication, resiliency is an all or nothing proposition for most of the population: you either pay for a backup system or are completely beholden to the bulk grid. 

Do we need a truly fractal grid? If we can power homes and critical businesses when the transmission system goes down, why should we target resiliency within entire distribution networks? 

This SunRun whitepaper, published in 2021, proposes distribution-level resiliency solutions for communities affected by wildfire-induced public safety power shut offs in California and paints a compelling picture of the benefits provided by a truly fractal grid. SunRun envisions a future where enough generation capacity and supporting hardware has been deployed on distribution networks to operate independently as needed, providing community resilience during service interruptions and load shaping services during normal conditions. This futuristic network is intelligent, in that it can smoothly transition between interfacing with the transmission system and operating independently as a snack-size ISO, coordinating the services of a diverse portfolio of privately-owned DERs through market constructs.

Several fruitful themes are packed into this vision. By operating at the neighborhood level, even those without the financial resources or technical means to install an on-site DER can access resilience when the bulk grid goes out; the community solar plant can still provide power to local customers, and neighbors with backup systems can still share or trade power. This creates a more equitable distribution of resilience while maintaining private ownership of assets through a method of centralized coordination by the Distribution System Operator (DSO) and decentralized control by community stakeholders. It also provides a community with the optionality to exit the transmission system if, or when, it is in its interest. 

What is also captivating is that the robust system awareness required to run this community microgrid maximizes the value of distribution grid infrastructure. As we electrify heating and transportation, squeezing every watt out of increasingly strained wires, substations, and pole-top transformers will be essential; the key question is whether the telemetry and software deployment necessary to provide this degree of flexibility is cost-prohibitive. However, as grids continue to see delivery charges rise as a proportion of total costs, investing in these sophisticated islanding capabilities may soon become economically competitive with the status quo – especially in areas with frequent service interruptions. 

The Fractal Grid: Part II

Pricier Wires – The price signal chimera – Interconnection bottlenecks 

In Cheaper Energy, Pricier Wires, Duncan highlights how delivery costs have become proportionally greater than the cost of generating power on many electricity bills throughout the US. This trend reflects the importance of optimizing consumption and generation at the grid edge in order to reduce the cost of delivering power, a service that Distributed Energy Resources (DERs) have the technical capabilities, yet limited financial incentives, to provide. 

An advantage of DERs is that they can be programmed to provide a variety of beneficial services, comprising a full “value stack”, because they are located at or near final points of consumption. Subsequently, to reach their full potential, this value stack should offer a suite of complementary price signals so asset owners can smoothly arbitrage between revenues from different levels: wholesale markets, distribution system optimization, and community or on-site resilience. Even now, with many fractured and arcane program compensation structures throughout the stack, co-optimizing between multiple levels increases the likelihood of deployment; paying back the upfront cost of a resilience-focused asset with market revenues or obtaining marginal resiliency benefits from an asset primarily deployed for financial reasons can help a project pencil. The deployment rationale depends on the particulars of each asset, as load shifting devices like smart thermostats cannot provide on-site resilience and there isn’t as much of an economic or climate case for diesel generators. But overall, the ability to co-optimize between different value streams should enable DERs to meet the most pressing need at each temporal and geographical juncture on the grid, creating a virtuous cycle where local price signals stimulate DER adoption and alleviate the constraint until grid conditions evolve and form new price signals. 

However, consumers considering adding a DER have limited mechanisms to access the full stack because the quality, unity, and form of the available price signals are complex and clunky. To reflect the full cost of generating and delivering power, as well as the value of modifying behavior to reduce these costs, any given DER receives a smorgasbord of static time of use rates, demand charges, and baseline methodologies depending on the particular utility, ISO, and program. Sometimes, price signals even contradict one another (case in point: co-optimizing time of use rates and baselines). Nowhere are price signals more static and ambiguous than those reflecting delivery costs from the distribution grid, which materialize as top-down, bespoke demand response programs for short-term constraints and vague delivery charges and NWA pilot projects for long-term constraints.

The key reason these price signals are of such poor quality is that operating the network in real time is entirely independent from interconnection analysis, which determines whether new sources of generation or load will violate the constraints of the equipment serving the site. The essence of NWAs is to circumvent the need for upgrading grid infrastructure in response to an interconnection request by maximizing the usage efficiency of existing poles and wires. This can be done by using the flexible consumption or generation offered by new or existing DERs to modulate power flow on distribution networks and avoid the constraint. Suboptimal usage and awareness of existing distribution infrastructure limits interconnection. If five homeowners on the same secondary circuit want solar but their shared transformer can only handle the maximum generation of three, two homeowners don’t get to interconnect their DER even if they’re drawn by the resiliency benefits or financial incentives. However, if one or more homeowners use batteries to modulate the generation of their solar + storage systems and avoid the constraint, it could make economic sense for all without requiring an upgrade.

Enabling these types of projects to proceed requires embedding the price signals for load shaping with the interconnection and distribution planning processes. This would enable my rooftop solar proposal to distribute mini-RFPs to the stakeholders on my local network to see who might be willing to add a DER in a strategic location or modulate their load for the right price. By the same token, a utility considering larger infrastructure upgrades could beam out RFPs to DER developers for coordinated deployment and operation of flexible devices. And some do.

However, current interconnection studies are primarily performed via physical site visits, emails, spreadsheets, and creaky, siloed power flow software. Some tools like hosting capacity maps alleviate the initial tediousness and have been folded into the interconnection process to a certain extent, but as many developers can attest, interconnection is a slow and painful technical process that takes several months to complete and often ends with an upgrade fee that breaks the project. Additionally, most of the few recognized NWA opportunities do not get implemented because the opaque cost-benefit analyses completed by utilities routinely deem decentralized solutions to be more expensive and less reliable. Even in New York’s Value of Distributed Energy Resources tariff, arguably the closest practical implementation we have to a theoretical ideal, the Locational System Relief Value (LSRV) is not available for all DERs and is completely at the discretion of the utility. 

In Justin Gundlach’s seminal paper on the value stack, notice how distribution system capacity value is updated roughly every decade.  

As electrification and deployment of distributed generation impose service upgrades, the current processes for distribution interconnection, planning, real time network management (via ADMS), and real time DER management (via DERMS)  should fuse together to evolve past siloed, project-by-project analyses into a true dynamic system of constraint identification and alleviation through the cheapest possible means. But today, not only does locational value trickle into the value stack, but the fragmentation and opacity of these services stymies DER installation. When comparing the state of interconnection and NWA assessment to the exponential demand forecasts for EVs, solar, storage, heat pumps, and other DERs produced by every market research firm, DER growth seems more quixotic than inevitable.

To break this barrier, utilities need greater awareness of when, where, and how flexible energy devices can squeeze greater efficiency out of their infrastructure and ensure the trustworthy coordination of decentralized assets. This requires data. 

Parts III and IV to be continued Thursday…

P.S. We are having our next NYC meetup in Brooklyn Wed 7/13. RSVP here if you plan to attend!

Transitioning from the Hydrocarbon Age to the Age of the Electron requires completely reframing how we build and interact with our energy systems. Burning fossil fuels for heat, electricity, and transportation (whether in a car, power plant, or boiler) is a fundamentally different process than using AC or DC power to drive motors or photovoltaics and wind turbines to generate electricity. As the tools we use change their mechanism for energy conversion and consumption, the electricity grid that feeds them will go through a paradigm shift as well.

This shift of end-uses of electricity to more critical tasks like heating our houses and charging our cars means the resiliency of local grid infrastructure will become more important than how “efficiently” we build our bulk grid. Most power outages today result in some minor inconveniences: you bust out candles and flashlights and realize that you may lose a few days of groceries in the fridge. But in the future, the dependence of mission critical uses like heat, internet connectivity, and transport on electricity makes losing power far more dangerous. The problem is that, today, our grids are designed such that they will continue to fail, despite our best efforts to harden them.

This need for local power sources and resilience will lead to the proliferation of Distributed Energy Resources. DERs is a category of new technologies ranging from electric vehicles, smart thermostats like Nest, battery storage, rooftop solar, backup generators, heat pumps, electric water heaters, and more. These so-called DERs are distinguished by the fact that they are digitally enabled, small, modular, and owned by end-consumers, not utilities, and can shift your power consumption to times when it’s most available and cheapest. Most importantly, some of them can store or generate power in your home, so if the grid goes down, your lights stay on. When considering all of their benefits in aggregate, it is easy to understand how a DER-heavy grid will be better than the system we currently have.

For the last 80 years, the grid was built around wholesale market and centralized power plant operational uptime in mind, also known as reliability. By contrast, it was not built to factor in the importance of individual nodes (like your house) staying active on the grid, also known as resilience. In order to build efficient, combustion-based generators, we needed to build them large enough to reach economies of scale and as a result, extensive transmission and distribution networks to transport power along with them. Those wires are vulnerable to being knocked out by storms (or even squirrels), leading to blackouts, and high degrees of interconnectedness are vulnerable to cascading failure via supply shortages. That was the deal we made: reliability and efficiency of bulk generation and transport over the resilience of local nodes in times of crisis. But in the Age of the Electron, inverting market design to value resilience over reliability will lead to a superior electricity grid.

Centralized grids will never not fail

Every time the grid fails, experts offer rationale for the outages such as market design, poor regulation, lack of weatherization, and more. But these analyses continually miss the forest for the trees and fail to address that the underlying system design across each of these markets is functionally the same. Our grids are highly centralized, and will continue to fail regardless of our best efforts at planning for worst case scenarios. There is no stopping these outages, and there are more to come.

Over a six month period in 2020-21, we witnessed three distinct grid failures in three different regions and climates of the US (CA, NY, TX) across three different market structures (centrally-planned, capacity, and energy, respectively) and for three different reasons (wildfires, wind, and cold, respectively). In August of 2020, California grid operators had to institute rolling blackouts due to a power supply shortage during a heat wave, and soon after had to shut down power to customers to deal with the risk of wild fires being started by the distribution grid (two separate reasons for blackouts!). In NY in August 2020, Hurricane Isaias knocked down enough wires that some customers were left without power for 7–10 days (an event like this happens most years). In February of 2021, a supply shortage in generation due to a variety of factors—but mainly a natural gas shortage—left Texans without power for multiple days in frigid temperatures, leading to untold damage and 246 deaths.

Whatever the cause of the recent and future outages, their frequency is expected to increase as climate change brings more extreme weather events, intermittent solar and wind present challenges in firm generation supply, and we continue to underinvest in an aging grid. Furthermore, centralized power grids in an electrified economy present an existential risk, so the danger these outages present are only going to increase.

Centralized grids are becoming single points of failure for an electrified society

We take for granted that our current energy — not electricity — infrastructure that supports fossil fuel driven processes is, for the most part, remarkably distributed and resilient because of our ability to locally store and convert these fuels cheaply. Boilers and cars are devices that turn potential energy (fuel) into work, or actions that are useful to us. To do this work, we store fuel in propane tanks in backyards, gas tanks in cars, and storage tanks underneath gas stations until needed. This means that we typically have days or weeks worth of fuel to heat our house if it’s cold when the power goes out (although most boilers need power to run). It’s also easy to go to a nearby gas station using a jerry can to lug fuel back for a diesel generator or car, so we’re never truly stranded if cars run out of fuel. When was the last time we legitimately could not do these things because there was no fuel? The 70's? That was one of the worst existential crises our real economy has faced since the Great Depression. On the other hand, outages are a regular occurrence on the electricity grid: nodes, until now, couldn’t function individually, unlike how cars and boilers can.

Meanwhile in the Age of the Electron, power is becoming increasingly central to our daily lives, meaning outages will become deeply problematic. On an electrified grid, if power lines in your neighborhood are taken out by falling trees, you won’t have heat and potentially no ability to drive anywhere. Your nearby EV charging station won’t have power either, so there’s no jerry can to save you. Furthermore, local municipal resources like bus lines, snowplows, and utility trucks to fix the lines may be handicapped. It could be days—if not weeks—without heat or any ability to move around, and supply chains may even be disrupted. You won’t be able to work because your router doesn’t have power and you can’t charge your computer. Your best hope is that there are some community centers with microgrids nearby, or you were smart enough to install a generator or battery in your home.

This is exactly what it looked like in Texas during Winter Storm Uri, primarily because Texans rely heavily on electricity for heat. Although the northern U.S. is better prepared for winter weather due to its reliance on gas heating, the kinds of challenges faced by Texas will soon happen everywhere on a fully electrified grid.  What’s more, during Uri the natural gas system was actually the primary cause of power failures, as power plants didn’t have enough gas to run due to shortages and pipes freezing, so it’s not as if today’s fossil-fuel based system is perfect, either.

Regardless, as heat and transportation (and  even industrial processes) transfer from gas distribution to electricity, we will be more exposed than we are now, since power grids do fail more frequently than gas systems. What matters is that all of these centralized systems are designed in such a way that it is impossible to build a perfect defense against all possible tail events. So these outages are just the beginning; we need a radical new way of building our energy systems, and particularly power grids. Luckily, DERs offer us the potential to build a better energy future than the power and gas systems combined.

A decentralized electricity grid will be superior to all prior energy systems

The future grid will be built from the bottom up, driven by new technologies, DERs, that are in many ways vastly superior to their predecessors. DERs such as rooftop solar, distributed wind (while not as popular today, they have been used by farming communities in the past), and geothermal heat pumps represent the first time in history we can cheaply generate energy independently and on a small scale, anywhere. All combustion-driven processes rely on a distribution network to benefit consumers, like natural gas pipelines or diesel and propane trucks. So while we can store these fuels easily, we cannot self-produce them, unlike with DERs. This idea is still greatly under-appreciated.

In order to accomplish the same thing a solar panel can, an individual would need to buy a generator, build an oil derrick, and have a refinery on site to be truly self-sufficient. With solar, it is all three of those in one; it produces power whenever there is sun, which can be directly used by onsite appliances. The same is true of geothermal heat pumps, which provide a constant, independent source of heating or cooling. Furthermore, electric vehicles and stand-alone storage are starting to get effective enough at providing stored power onsite cheaply, like their fossil-fuel predecessors. What this amounts to is that a home with solar, storage, a geothermal (or stand-alone) heat pump, and an EV will soon actually be more resilient than a home with a natural gas boiler.

These new technologies have arrived just in time, as the twin problem of electrification and increasing outages requires policy makers, grid operators, and power companies alike to rethink grid planning. This is a marked departure from the grid as it looks today.

DERs differ drastically from thermal plants, and thus the grid must look different too

Our grid was built in a centralized manner because of technological constraints that no longer exist. In the past, our power generation sources relied on combustion to drive them, so building larger and larger centralized power plants would lead to maximum thermodynamic efficiencies at scale, and thus would yield the cheapest power. This then required large transmission and distribution (T&D) networks to transport the power from low population density areas, generally where there was cheap land to build power plants, to high density areas like cities. This introduced the grid’s fundamental, unavoidable weak point that cannot be designed away: wires. We did what we could with the technology we had, and structured our markets in a particular way as a result. Edge users that needed constant uptime like hospitals, data centers, etc all had to pay for resilience via onsite generators. Building onsite resilience was considered redundant to the bulk grid and thus was deemed “inefficient”.

But DERs are changing the underlying techno-economics of the grid, so grid planning won’t be far behind. The primary difference is that solar and batteries have the potential to be cost competitive with utility scale on a per unit basis, unlike their thermodynamic predecessors. This is because solar panel and battery storage efficiency does not scale with size, and thus we don’t need to seek the economies of scale we used to. While in the US a wholesale solar farm in say, West Texas, will currently produce power for less than the rooftop panels seen in the image below on a $/kwh basis, this does not have to be true. For example, in Australia, rooftop solar is $1219/kw and utility scale is $1061/kw, whereas in the US it’s $3520/kw ($4,236/kw in CA) and $1101/kw, respectively, due to high costs from slow bureaucratic processes like permitting that exist in the US. If treated as a wholesale power plant alone (and we could slash red tape in the US), utility scale would have a slight edge over rooftop solar, but considering the fact that rooftop solar doesn’t need to be transported very far, the return it ends up receiving can be higher than utility scale because it is being compensated for lessening the need for extensive poles and wires. This is also without factoring the value of resilience to end users. These under-appreciated benefits make it seem like modular rooftop solar is a worse-returning asset for grids than large-scale renewables, when in fact the opposite may be true.

Viewing DERs as redundant to the bulk grid is thus a mistake, since they can do what bulk power plants can’t do. Current market structures don’t recognize this fact, and as a result compensate them in a haphazard way, if at all. DERs provide three core values to the grid: they act as wholesale power plants (individually or aggregated) by providing energy and capacity (or other ancillary services) to markets, they reduce our need for the poles and wires by being at or closer to demand, and they provide resilience to the end user. Markets today are starting to get better at being more explicit about the first two (like VDER in NY), but none still are effective in the third. Most importantly, large, bulk power plants can’t provide the second and third value. Since the these new, modular technologies provide added benefits to the grid that large plants can’t and their very nature is such that the unit economics are for the most part independent of scale, the grid will become distributed. It’s a techno-economic inevitability.

Market frameworks must adapt to create a clearing price for resilience

Since the techno-economics of DERs will drive a more distributed grid, our market frameworks should adapt to make sure they are being compensated fairly. The first step in this proliferation of DERs will be to give them access to markets to act like a big power plant as well as compensate them for the avoided T&D build out benefits they bring. This is using the existing framework as best we can. From there, we will be able to start considering new frameworks that appropriately compensate DERs for the resilience they offer in order to start fully accounting for the value they bring. This would require addressing the true costs of outages that occur both from supply shortages and from T&D outages, which markets today are not equipped to do. There are currently very few markets in the US that quantify these deferred T&D costs effectively, so consumers still need better price signals to fully recoup the costs of their investment. Furthermore, customers seeking resilience today must implicitly price the externalities of power outages, with no help from the power market. Thus, what’s so striking about DERs is that if markets are designed effectively, they have the potential to actually be economically superior to utility scale plants.

Even if large power plants and efficient bulk power markets seem cheaper for a while, when these tail events occur, they reveal enormous, previously hidden costs—the cost of resilience. In the case of Winter Storm Uri in Texas, the average price of power in the time period 2010-Feb 2021 in Texas jumped from $30.5/mwh to $43.6/mwh. That is, a three-day event raised average prices by 42% for an entire decade. So not only did markets become less efficient (more expensive) when the tail event occurred, the economic losses or externalities of users VOLL aren’t even reflected in this price jump, which totaled anywhere from $100billion to $300billion across the state. Ironically, the only wholesale market that somewhat tries to address this is ERCOT, through the concept of the Value of Lost Load (VOLL), which is a customers’ willingness to pay to avoid an outage and should theoretically match the cost of damages from the storm.

When grid planners forced outages during Uri, they eliminated the users’ ability to decide to pay more for power, even if their willingness to pay was higher than the wholesale market price cap. ERCOT had set the price cap of markets at $9,000/mwh, even knowing that many users VOLL is as high as $42,000/mwh. If an outage is occurring from a supply shortage, rolling outages should thus be based on users’ willingness to pay, because the costs of losing power are borne by that user anyways—a user with a VOLL of $42,000/mwh is better off paying $20,000/mwh than being shut off at $9,000/mwh. This however, would require utilities to be able to route outages at individual meters, and for every customer (or their provider) to understand demand response. The former is already a feature we have the technical capabilities to implement and being pursued by grid planners in areas like Texas, while the latter is growing rapidly through a variety of innovative new business models bringing more demand response solutions to market.

If everyone could participate in demand response, markets wouldn’t need price caps, which are effectively a redistribution of costs from users with VOLLs below the cap to those with VOLLs above them. Admittedly, if the price cap is sufficiently higher than most individual VOLLs, users still have enough incentive to invest in DERs, but it essentially caps the returns on their investment at the spread between their VOLL and the cap, weakening the signal and pushing the true costs of outages external to power markets. While eliminating price caps (again contingent on widespread demand response) may sound radical, remember that users are paying these costs external to the market anyways, and that electricity would just start looking like all other commodities where customers actually respond to prices. How many other commodities do have price caps? Doing so would create a more explicit clearing price for resilience and users would be able to more efficiently measure the tails and deploy capital to protect against them. Because they can understand their individual VOLL, they can see how frequently the market would go there, and invest on onsite capacity via DERs accordingly. Counter-intuitively, this would be more fair to users, not less so, as it would allow them to properly price and receive payouts (during high price events) for insurance for themselves by eliminating the opaqueness of the externalities of outages.

VOLL, however, does not address the other type of outage that can occur from delivery of the power itself. In the current paradigm, because poles and wires are an unavoidable design feature, outages from supply shortages are seen as a market failure, but outages from wires getting knocked down are seen as just the unfortunate reality of the grid. Because of this, resilience isn’t really seen as an attainable goal—who can you hold accountable for hurricanes knocking wires over time after time? It’s admittedly hard to promise it won’t happen to customers and price the service as a result. Thus, it’s not enough for grid planners at wholesale level to take a more rigorous approach to VOLL. The price of power could be determined more efficiently, but that doesn’t mean users could have guaranteed delivery of it. Thus, trying to create clearing prices for resilience would force us to look at the wires side of the equation too.

An example of how this could work would be focusing on resilience-driven Service Level Agreements (SLAs) such as endpoint uptime between users and power providers or utilities. Given that promising resilience requires both procuring sufficient power and delivering it, this may actually lead to a re-emergence of vertically-integrated T&D infrastructure and power suppliers. If this too sounds scary, consider that DERs inhibit the formation of natural monopolies in distribution infrastructure, so vertical-integration doesn’t necessarily imply regional monopolies, as it does today. And in fact, this already exists. Microgrid developers are essentially vertically-integrated providers, because they own both generating resources and delivery infrastructure. Their contracts are frequently structured as SLAs, too. It just happens to be behind the meter, and the delivery infrastructure isn’t very extensive. Thus, this future will naturally emerge as the number of microgrids and DERs increase. At a certain point, interconnecting disparate systems, particularly in rural areas, may make sense. Far from leading to lots of off-grid users, one could imagine simply a lot more, smaller T&D and generation owners that are interconnected with each other using the common standards (enforced by PUCs) that we already have developed today, and did not exist when vertical integration originally emerged in the early 20th century.

Regardless of how it looks—the above discussion is a thought experiment—by looking at endpoint uptime as a key metric instead of wholesale market uptime, we would start to approach markets with an entirely new framework. And with proper market design that effectively incorporates the currently hidden externalities into power market price signals, DERs will lead to a cheaper grid. Most importantly, the debate around the costs of DERs vs. centralized power plants ignores this reality, and the simple proof of this is that many people buy DERs for resilience, whether they “pencil out” financially or not. Until now, average users didn’t have as much of a need for local resilience or a choice of how to acquire it, so they primarily focused on cost too. But now that these options are available, the centralized grid continues to fail, and electrification is making resilience more valuable, more and more users will adopt DERs each time there is a new outage, whether or not they deliver savings or our markets compensate them properly. Since individual actors are adopting these solutions on their own today, we don’t need to wait around for markets to adapt. This reveals a core truth about the power of a bottoms-up, distributed grid in contrast to the top down models we have today: individual actors are implicitly pricing these hidden externalities, and will do that far more effectively than any central planner focused on “efficiency” ever could. It would be a lot better for everyone if markets reflected this reality.

Conclusion: Resilience for the win

Resiliency is the killer application  of DERs. One need look no further than how the search traffic from users asking “how can I install a battery in my house?” spikes after wildfires in CA, hurricanes in NY, or big freezes in Texas once again knock out the power grid. This is a now universal problem and overtime resiliency benefits will lead to more and more users adopting these superior technologies, especially as electrification increases the value of resilience. As more individual users adopt, the collective will benefit.

What this means is that we shouldn’t care if the overall costs of a distributed system are higher than a centralized one (which likely isn’t even true). Asking about average levelized power costs is just the wrong question, as it frames the debate in the old paradigm’s terms. The right questions are how do we organize our energy systems to fulfill individual needs? How do we provide value? How do we make sure lower income communities get microgrids too? How do we lower the costs of T&D build out, and not just energy supply costs? A new paradigm for market design will emerge out of answering those questions effectively. And as resilience and efficiency are antitheses of each other, I’m arguing that in the future, one is more important than the other. This is not to say that the grid will become hyper fragmented. Bulk power plants like nuclear, hydro, geothermal, solar, and wind will all play their role, but the underlying architecture of institutional powers on the grid must change.

While in the past the God of Efficiency confidently decreed that “reliability” mattered more than individual or distribution grid (local) outages, or “resiliency”, the future grid will invert that relationship. Micro resilience over macro reliability. Local redundancy over bulk efficiency. Safety—which is what customers value anyways—over cost. And as the grid continues to fail, users will show how obvious this choice really is.

To kick it off, we are featuring Duncan Campbell and his piece Cheaper Energy, Pricier Wires from his newsletter State of Charge. We hope you enjoy!

Cheaper Energy, Pricier Wires

The slept-on trend that threatens decarbonization, and how we'll fix it.

Shortly after covid hit the US and the work from home era began, I looked into buying a bottle of shampoo online. I used to always grab things like that at the drug store next to my office, so without an office to leave, I kept forgetting to buy it. Unfortunately, shipping would have more than doubled its cost, which I couldn’t stomach. Instead, I wrote “BUY SHAMPOO, IDIOT” on a post-it note and put it on my front door.

Increasingly, this is what buying electricity in the US may feel like.

Your electricity bill has two elements: the cost of generating power and the cost of delivering it. People typically assume their bill is mostly or exclusively driven by the former. Far off power plants produce energy, they sell it into the wholesale market, and those costs eventually get passed on to consumers.

In reality, the cost of building and maintaining all the infrastructure to get power to your house (transmission lines, substations, distribution networks, transformers, etc.) is a significant portion of your bill. In fact, when working with large energy users across the country, I even see utility bills where a majority of costs are associated with delivery.

And one of the most slept on trends in the energy industry is that this portion is growing rapidly. According to the US Energy Information Administration,

“After adjusting for inflation, major utilities spent 2.6 cents per kilowatthour (kWh) on electricity delivery in 2010, using 2020 dollars. In comparison, spending on delivery was 65% higher in 2020 at 4.3 cents/kWh. Conversely, utility spending on power production decreased from 6.8 cents/kWh in 2010 (using 2020 dollars) to 4.6 cents/kWh in 2020.”

Put simply, generating power is getting cheaper while delivering it becomes more expensive. In this post I will show how the utility business model creates this situation, how it can meaningfully slow the energy transition, and why DERs must challenge the monopoly if we want to fix it.

Why’s this happening?

Generating power has been getting cheaper for the last 20 years. In the early 2000s we built a truly massive fleet of natural gas power plants, just in time for the fracking revolution to unlock enormous quantities of low cost fuel for them.

Also, wind and solar began to get super cheap, which led to rapid deployment. Even at relatively low market shares, wind and solar suppress wholesale energy prices because they have zero marginal costs. And thanks to incredible learning rates for these technologies, we can only expect this to continue.

But cheap gas, wind, and solar are not the full story — simultaneously, delivery costs are also increasing. Exactly why this is occurring is hard to succinctly answer. Experts will cite many factors, including replacing aging grid equipment, implementing new smart technologies, and building new transmission lines to access the best locations for wind and solar power.

However, there is another explanation of these costs that is more controversial among experts. Power delivery infrastructure is the last bastion of the electricity monopoly, and from it, utilities intend to grow.

For context, here’s a quick history of electricity regulation:

• Historically, the generation and delivery of electricity was a monopoly granted by the state. Utilities built everything needed for us to have electricity, and were allowed to earn a regulated and guaranteed return on all of that capex.

• During the 1990s, energy market liberalization swept across the nation. Under this new paradigm, utilities were removed from the power generation process. While building and maintaining the power delivery system was considered a natural monopoly for which the traditional regulatory model still made sense, generating power was now conceived as a competitive market, where many players would compete to drive down the commodity cost of electricity. Note that, this only spread to about half the country.

• In 2005 electricity demand growth stopped. After decades of consistent growth, energy efficiency and industrial offshoring kept electricity demand flat. This meant utilities couldn’t build more stuff for the purpose of delivering more power.

Since utilities couldn’t make money on power generation any more, and there was no new load to justify new delivery infrastructure they could earn a return on, the utility business pivoted to deploying more and more capital into delivering power for existing demand. This resulted in an increasing unit cost of electricity delivery.

To be fair, there are good reasons to deploy more capital into delivering power for existing load. Smart grid technologies like advanced metering infrastructure (aka “smart meters”) cost money. However, if used well, these technologies also should help reduce peak demand on the grid, meaning future load growth can be served with less new delivery infrastructure. Therefore, the utility’s natural incentive is to convince their regulators to allow for deployment of this smart technology, which is capex they can receive a return on, but then not fully utilize it. That way, any new demand which may materialize can still be served with even more capital investment.

In short, the utility’s incentive is to deploy capital inefficiently, and all of that effort has been almost exclusively focused on delivery infrastructure for decades.

Decarbonization is levered to cheap electricity

There are obvious downsides to electricity becoming more expensive. For industry, high prices hurt the bottom line. For residential consumers, one can be forced to choose between a credit card balance and keeping the heat on. But within the more specific context of electricity generation becoming cheaper while its delivery cost increases, the impact on electrification should be considered.

The term electrification is used to describe fuel-switching a fossil-fuel energy demand to electricity. The two most common examples of this are electric vehicles and heat pump electric heating. Both are considered by most in the energy sector to be essential parts of decarbonization. The idea is that if we switch as much energy use to electricity as possible, then unlike when using fossil fuels, we can clean up the electricity source.

One reason electrification is supposed to be economical (in addition to sustainable) is that making power through renewables and batteries is getting cheaper by the day. As the power system converts to these sources, electricity prices should come down, making electrification economics more attractive. Or so the theory goes.

But if delivery costs continue to increase at the current pace, they’ll eat any savings generated by large-scale solar and wind. This is a problem for decarbonization, when around 130 million Americans live in a state where replacing an old gas furnace with a heat pump would create higher energy costs than simply buying another gas furnace (ignoring the higher capex as well).

And this doesn’t just impact residential home electrification. Buried in the business model of virtually every new and exciting decarbonization pathway (direct air capture, H2 for steel and shipping, e-fuels for aviation, etc.) is the assumption of very low cost electricity inputs made possible by renewables. You can listen to this episode of The Interchange for a deep dive on the subject, but the quick version is if that cheap renewable energy input is to be accessed via the grid, then delivery costs once again become a problem.

If we want rapid climate action the cost of electricity needs to fall, but its delivery costs may get in the way.

Load Defection? More like load optimization.

Another outcome of rising delivery and declining generation costs is electricity users will try to avoid those delivery costs. This will be accomplished by building on-site power systems or migrating to locations adjacent to existing cheap energy generation.

The former is becoming commonplace. Homes and businesses are installing on-site solar and storage at a rapid pace, and while they may not realize it, they are doing so to avoid delivery costs. The economics of this choice are often superior to signing up for a grid-delivered power contract because each unit of energy generates value at the retail rate (inclusive of delivery costs) rather than wholesale rate. And as the march of technology learning rates continues, the quantity of locations where this choice makes sense will grow.

Simultaneously, load will begin to migrate to places where large wind and solar projects already exist, in attempt to offtake power directly. This has started to happen with new industrial energy loads like hydrogen production and crypto-currency mining because they are extremely sensitive to the cost of power. Soon, other new-build industrial sites will do the same. And eventually, when this dynamic becomes compelling enough, businesses will even consider moving from their existing facilities to capture low cost power directly from large-scale energy sources. If you can avoid the distribution grid, you will.

In the electricity industry we refer to this as load defection, for which the primary concern is the so called utility death spiral. If load defection accelerates, delivery utilities will experience significant decline in energy sales, necessitating rate increases to pay for fixed infrastructure costs. This leads to more load defection, and the cycles continues. This is considered problematic because it will leave those without on-site power systems shouldering the cost of the delivery infrastructure we all (including on-site energy users) rely on.

This argument has been used to levy prejudicial fees on customers with on-site generation, and while this may seem logical, it ignores a crucial consideration; short-run versus long-run costs.

It is true that existing grid delivery assets are fixed costs. Reducing energy consumption from the utility doesn’t reduce the cost of that infrastructure. Once it exists, we’re stuck with it. However, reducing energy consumption (at the right times, more on that later), absolutely does decrease the need for future delivery infrastructure. If the delivery infrastructure needs to support “x” peak load today, and 1.5x at some point in the future, then a 0.25x reduction today means we only need to support 1.25x in the future. While it doesn’t translate immediately into delivery infrastructure savings, it most certainly will over time.

This matters because, while load hasn’t grown for 15+ years, it is about to explode. Earlier I mentioned electrification to show how increasing electricity delivery costs are a problem for decarbonization, but what I didn’t describe was the extent to which this will transform our electricity system. A study from the National Renewable Energy Laboratory (NREL) found high levels of electrification (but not even full electrification) will result in the power system requiring between 2 and 3.5 terawatts of generation capacity, relative to our 1.1 terawatts today.

Doubling or tripling our generating capacity will require a ton of new delivery infrastructure. It follows that reducing load on-site with distributed energy will absolutely reduce total delivery system costs. In turn, this means distributed energy will help keep delivery rates low for everyone, which is a very different outcome than the dystopian utility death spiral narrative some would lead you to believe.

Load defection is good for the grid, because it makes room in our existing delivery infrastructure to accommodate electrification. That results in a more optimized, cheaper power system for all, while making successful decarbonization more probable.

Virtual wires, the next frontier of liberalization

Earlier we established that the core monopoly utility incentive is to deploy capital inefficiently. With this in mind, utilities aren’t an ideal choice to own or operate the distributed energy technologies that will keep delivery rates low in the face of huge new load growth from electrification.

Instead, a variety of market participants should develop these solutions and be financially exposed to their performance. For example, what is the best way to deploy a smart thermostat to shift demand patterns? If the utility installs it, or even just controls it, chances are it will never be properly utilized. But when an end-user or their company of choice installs it, because they’re taking the risk on it working, you can be sure they’ll do everything they can to achieve the best outcome.

Consider that about a decade-ago the utility sector and its regulators began talking about Non-Wires Alternatives (this concept). Over that time, a few pilots have taken place, and much ink has been spilled about them, but no sincere effort has been made to turn this into a scalable approach for managing grid infrastructure costs. The common thread across all of these pilots was utility management of the programs.

The case for this is no different than that which led to wholesale power markets. Providing the service of avoided distribution infrastructure, or virtual wires, is not a natural monopoly, so it would be sub-optimal to treat it as one.

One key challenge to achieving this future will be designing the right price signals to properly compensate virtual wires for the value they offer. Options include incorporating these future charges into electricity bills and letting users install DERs to reduce them (rate design), implementing programs that compensate virtual wires services providers directly via the rate base (a DSO type market perhaps?), tariff programs that transact through the utilities (like NY’s VDER), and likely many other things. Whatever the best price signal is, we should strive to make it clear and standardized across the country. If every regulatory fiefdom takes a different approach, we’ll wind up with high transaction costs and providers that can’t scale.

A second challenge will be that utilities likely won’t appreciate this vision. The existence of virtual wires is conceptually (not legally) a challenge to their franchise right, the state-granted monopoly for building electricity delivery infrastructure. This will invariably lead to policy battles that force us to reckon with the fundamental nature of the monopoly regulatory model. And this battle probably wont be fair, given when backed into a corner utilities are known to fight in distasteful (astroturfing) or even illegal (bribery) ways.

Despite these challenges, managing the delivery cost problem and the system change implied by its solution will be a major theme as electrification grows. If we want a power system that is prepared for the challenges of the future and supports human prosperity, we must be successful in this endeavor.